Text

Official Exhibit - NYSR0014E-00-BD01 - UFSAR, Rev. 20 Indian Point Unit 2 (Submitted with License Renewal Application) (2007) (IP2 UFSAR, Rev. 20)
	ML12335A439
Person / Time
Site:	Indian Point
Issue date:	12/22/2011
From:	; - No Known Affiliation
To:	; Atomic Safety and Licensing Board Panel
	SECY RAS
References
	RAS 21611, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
	Download: ML12335A439 (188)
	v • d • e

{{#Wiki_filter:United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of: Entergy Nuclear Operations, Inc. NYSR0014E (Indian Point Nuclear Generating Units 2 and 3) Revised: December 22, 2011 v....~f\ REGU<..q" ASLBP #: 07-858-03-LR-BD01

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Docket #: 05000247 l 05000286

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IP2 FSAR UPDATE TABLE 6.2-3 (Sheet 3 of 3) Quality Standards Of Safety Injection System Components

2. Hydrostatic test of tank

3. Hydrostatic test of tank heater coil

4. Spot radiography of longitudinal and girth welds B. Special manufacturing process control

1. Weld, fabrication, NOT, and inspection procedure review

2. Surveillance of suppliers quality control and product

3. Material chemical and physical properties certification Notes:

1. Except Internal Recirculation Pump.

2. For valves with radioactive service only.

TABLE 6.2-4 Accumulator Design Parameters Number 4 Type Stainless steel lined/ carbon steel Design pressure, psig 700 Design temperature, OF 300 Operating temperature, OF 100-150 Normal operating pressure, psig Note 2 Total volume, fe (each) 1100 Water volume at operating conditions, fe (each) Note 2 Minimum boron concentration (as boric acid), ppm 2000 Relief valve setpoint, psig 1 700 Notes:

1. The relief valves have soft seats and are designed and tested to ensure exceptional tightness.

2. Minimum and maximum operating pressure and volume are controlled by Technical Specifications.

Cha pter 6, Page 44 of 170 Revision 20 OAG10000215_0753

IP2 FSAR UPDATE TABLE 6.2-5 DELETED TABLE 6.2-6 Refueling Water Storage Tank Design Parameters Number: 1 Material: Stainless Steel Nominal Capacity, gal. 350,000 Volume Required by Technical Specifications 345,000 (solution), gal. Normal pressure, psig Atmospheric Operating temperature, of 40-110 Design pressure, psig Atmospheric Design temperature, of 120 Boron concentration (as boric acid), ppm 2400 (minimum) Type of heating Steam Cha pter 6, Page 45 of 170 Revision 20 OAG10000215_0754

IP2 FSAR UPDATE TABLE 6.2-7 Pump Design Parameters Safety injection pump Number 3 Design pressure, discharge, psig 1750 Design pressure, suction, psig 200 Design temperature, of 285 Design flow rate, gpm 400 Maximum flow rate, gpm 650 Design head, ft 2500 Shutoff head, ft 3550 Material Martensitic stainless steel Motor, hp 400 Type Horizontal centrifugal Recirculation pump Number of pumps 2 Type Vertical centrifugal Design pressure, discharge, psig 250 Design temperature, of 300 Design flow, gpm 3000 Design head, ft 360 Material Austenitic stainless steel Maximum flow rate, gpm 4428 Shutoff head, ft 476 Motor, hp 350 Residual heat removal pump Number of pumps 2 Type Vertical centrifugal Design pressure, discharge, psig 600 Design temperature, of 400 Design flow, gpm 3000 Design head, ft 350 Material Austenitic stainless steel Maximum flow rate, gpm 5500 Shutoff head, ft 390 Motor, hp 400 Cha pter 6, Page 46 of 170 Revision 20 OAG10000215_0755

IP2 FSAR UPDATE TABLE 6.2-8 Residual Heat Exchangers Design Parameters Heat Exchangers Number 2 Design heat duty, Btu/hr (Normal) 30.8 X 106 Design UA 1 , Btu/hr-oF 1.2x106 Design cycles (85°F - 350°F) 200 Type Vertical shell and U-tube Normal condition Tube side Shellside Design pressure, psi 600 150 Design flow, Ib/hr 1.44 X 106 2.46 x 106 Inlet temperature, of 135 88.3 Outlet temperature, of 113.5 100.8 Notes:

1. Total heat transfer coefficient x Area.

Chapter 6, Page 47 of 170 Revision 20 OAG10000215_0756

IP2 FSAR UPDATE TABLE 6.2-9 Estimated External Recirculation Loop Leakage3 Items Number Type of Leakage to Leakage to of Units Leakage Control Atmosphere Tank (cm 3/hr) and Unit (cm 3/hr) Leakage Rate Residual heat 2 Mechanical seal 01 6 removal pumps with leakoff-(low-head safety drop/min injection) High-head safety 3 Same as 01 9 injection pumps residual heat removal Flanges: Gasket-adjusted to zero leakage following any test - 10 drops/min per flange

a. Pump 15 450 1 0

b. Valves - 16 480 2 0 Bonnet to Body (larger than 2-in.)

Valves - stem 6 Backseated, O2 6 leakoffs double packing with leakoff 1 cm 3/hr-in.stem diameter Misc. small valves 23 Flanged body 692 0 packed stems - 1 drop/min Totals 999 21 Notes:

1. Total estimated leakage from RHR and SI pump mechanical seals and flanges is 450 cc/hr.

2. The total leakage estimated from all sources including valve stem leakage, packing leakoffs, flanged body packed stems and other potential sources (pumps and flanges) of External Recirculation Loop is 999 cc/hr.

3. Actual measured leakage is limited by Technical Specifications. The radiological consequences of external recirculation loop leakage following a design basis accident are presented in Section 14.3.6.6.

Cha pter 6, Page 48 of 170 Revision 20 OAG10000215_0757

IP2 FSAR UPDATE TABLE 6.2-10 (Sheet 1 of 3) Single Active Failure Analysis - Safety Injection System Component 1 Malfunction Comments A. Accumulator (injection Deliver to broken Totally passive system with phase) loop one accumulator per loop. Evaluation based on three accumulators delivering to the core and one spilling from ruptured loop. B. Pump: (injection phase)

1. Safety injection Fails to start Three provided. Evaluation based on operation of two.

2. Residual heat removal Fails to start Two provided. Evaluation based on operation of one.

3. Essential service water Fails to start Three provided. Evaluation based on operation of two.

4. Component cooling2 Fails to start A total of 1 of 3 required during recirculation.

5. Nonessential service Fails to start A total of 1 of 3 required water2 during recirculation.

6. Recirculation2 Fails to start Two provided. One required to operate during recirculation.

7. Auxiliary component Fails to start Two provided. Operation of cooling pump these pumps is no longer required.

Cha pter 6, Page 49 of 170 Revision 20 OAG10000215_0758

IP2 FSAR UPDATE TABLE 6.2-10 (Sheet 2 of 3) Single Active Failure Analysis - Safety Injection System Component Malfunction Comments C. Automatically operated valves: (open on safety injection signal) (injection phase)

1. Safety injection line Fails to open (if Active failure to open is not isolation valve at the loops closed) credible since the injection valves are maintained in the open position when the reactor is critical.

2. Residual heat removal line Fails to open Two parallel lines, one valve in isolation valve at residual either line is required to open.

heat exchanger discharge

3. Isolation valve on Fails to open Two parallel lines, one valve in component cooling water either line is required to open.

line from residual heat exchangers D. Valves operated from control room for recirculation: (recirculation phase)

1. Recirculation sump internal Fails to open Two lines in parallel, one valve recirculation isolation in either line is required to open.

2. Safety injection pump Fails to open Two parallel lines, one valve in suction valve at residual either line required to open.

heat exchanger discharge

3. Isolation valve on the mini- Fails to close Two valves in series, one flow line returning to the required to close.

refueling water storage tank

4. Isolation at suction header Fails to close Two valves in series, one from refueling water required to close (one valve is storage tank to safety a check valve).

injection pumps Cha pter 6, Page 50 of 170 Revision 20 OAG10000215_0759

IP2 FSAR UPDATE TABLE 6.2-10 (Sheet 3 of 3) Single Active Failure Analysis - Safety Injection System Component Malfunction Comments

5. Residual heat removal pump Fails to close Two valves in series, one recirculation line required to close.

6. Residual heat removal pump Fails to close Two valves in series, one discharge line required to close (one valve is a check valve).

Notes:

1. The status of all active components of the safety injection system is indicated on the main control board. Reference is made to Table 6.2-2.

2. Recirculation phase.

Cha pter 6, Page 51 of 170 Revision 20 OAG10000215_0760

IP2 FSAR UPDATE TABLE 6.2-11 (Sheet 1 of 2) Loss Of Recirculation Flow Path Flow Path Indication Of Alternative Loss Of Flow Path Flow Path 1 Low head recirculation From recirculation sump to low-head injection header 1. Insufficient flow in From recirculation sump to via the recirculation pumps low-head injection lines high-head injection header and the residual heat (one flow monitor in via the recirculation pumps, exchangers each of the four one of the two residual heat low-head injection exchangers and the safety lines2) injection pump.3

2. As 1 above. a. From containment sump to discharge header of the residual heat exchangers via the residual heat removal pumps.

b. If flow not established in low-head injection lines, as (a), except path is from discharge of one residual heat exchanger to the high-head injection header via the safety injection pumps.

Cha pter 6, Page 52 of 170 Revision 20 OAG10000215_0761

IP2 FSAR UPDATE TABLE 6.2-11 (Sheet 2 of 2) Loss Of Recirculation Flow Path Flow Path Indication Of Alternative Loss Of Flow Path Flow Path 1 High-head recirculation From recirculation sump to 1. No flow in high-head a. From containment sump high-head injection header injection header (four to high head injection via the recirculation pumps, flow monitors, one in header via the residual one of the two residual each cold leg injection heat removal pumps, exchangers and the high- line and one pressure one of the residual heat head injection pumps monitor) exchangers and the high-head injection pumps.

b. If flow is not established in high-head injection header - as (a), except path is from discharge of the residual heat removal pumps to the high-head injection pumps via the middle safety injection pump (by-passing the residual heat exchangers 4).

2. Flow in only one of the a. As 1(b), except that flow two high-head injection from the middle safety branch headers (two injection pump is only flow monitors per supplied to the unbroken branch header) branch header.

Notes:

1. As shown in Plant Drawings 9321-2735 & 235296 [Formerly UFSAR Figure 6.2-1], there are valves at all locations where alternative flow paths are provided.

2. If minimum flow requirements have been established, the supply of recirculated water using low-head recirculation will maintain the core flooded even in the event of a low-head spilling line and one failed flow meter or other single failure.

3. Manual start"

4. In this recirculation mode, water is returned to the core without being cooled by the residual heat exchangers. Heat is removed from the core by boiloff of the water to the containment; heat is then removed from the containment by either the containment fan coolers and/or the containment spray system (using cooled water from the recirculation sump via the recirculation pumps and one residual heat exchanger).

Cha pter 6, Page 53 of 170 Revision 20 OAG10000215_0762

IP2 FSAR UPDATE TABLE 6.2-12 Shared Functions Evaluation Coml2onent Normal Normal Accident Accident Operating Operating Function Arrangement Function Arrangement Refueling water Storage tank for Lined up to Source of Lined up to storage tank refueling suction of safety borated water for suction of safety operations injection, core and spray injection, residual heat nozzles residual heat removal, and removal, and spray pumps spray pumps Accumulators (4) None Lined up to cold Supply borated Lined up to cold legs of reactor water to core legs of reactor coolant piping promptly coolant piping Safety injection None Lined up to hot Supply borated Lined up to hot pumps (3) and cold legs of water to core and cold legs of reactor coolant reactor coolant piping piping Residual heat Supply water to Lined up to cold Supply borated Lined up to cold removal pumps core to remove legs of reactor water to core legs of reactor (2) residual heat coolant piping coolant piping during shutdowns Recirculation None Lined up to cold Supply borated Lined up to cold pumps (2) legs of reactor water to core legs of reactor coolant piping, and spray coolant piping, spray headers nozzles from spray headers and suction of recirculation and suction of safety injection sump safety injection pumps pumps Service water Supply river One or two Supply river Lined up to non-pumps (non- cooling water to pumps in service cooling water to essential service essential component component water header 1 header) (3) cooling heat cooling heat exchangers and exchangers non-nuclear components Component Supply cooling Up to three Supply cooling Lined up to CCW cooling pumps water to station pumps in service water to residual header 1 (3) nuclear heat components exchangers, S.I. pump bearings and recirculation pump motor coolers Residual heat Remove residual Lined up for Cool recirculated Lined up to exchangers (2) heat from core residual heat water in discharge of during shutdown removal pump containment for recirculation Cha pter 6, Page 54 of 170 Revision 20 OAG10000215_0763

IP2 FSAR UPDATE operation core cooling and pumps or RHR containment pumps spray Component Remove heat One or two heat Cool water for Both heat cooling heat from component exchangers in residual heat exchangers in exchangers (2) cooling water service exchangers and service other services Auxiliary None Lined up for Provide Lined up for component pump operation component pump operation cooling pumps cooling water to (2) recirculation pump motor coolers Service water Supply river Up to three Supply river Lined up to pumps (essential water to station pumps in service cooling water to essential service header) (3) safeguards safeguards water header components Notes:

1. Recirculation Phase.

TABLE 6.2-13 Accumulator Inleakage1 Time Period Between Observed Leak Rate Observed Leak Rate Level Adjustments (cm 3/ hr) Maximum Allowed Design 1 month 1955 99.8 3 months 665 33.3 6 months 333 16.7 9 months 221 11.1 1 year 167 8 10 years 16.7 0.8 Notes:

1. A total of 83.3-fe, added to the initial amount, can be accepted in each accumulator before an alarm is sounded.

Cha pter 6, Page 55 of 170 Revision 20 OAG10000215_0764

IP2 FSAR UPDATE TABLE 6.2-14 Residual Heat Removal System Design, Operation, And Preoperational Test Conditions Heat Pipes And Pumps Exchangers Valves Fittings Design conditions Pressure, psig 600 600 665 700 Temperature, of 400 400 400 400 Operating conditions (max.)- During recirculation2 Pressure, psig 232 232 232 232 Temperature, of 277 277 277 277 Preoperational Hydrostatic 1200 900 1100 900 Test pressure, psig Notes:

1. Located inside containment.

2. These maximum values have been conservatively calculated assuming saturated conditions at the containment design pressure of 47 psig to demonstrate that significant margin exists between design, normal operating and hypothetical accident conditions.

These values are used to support the conservatism of Table 6.2-9 and are not used in the Chapter 14 Accident Analysis or for any other purpose. 6.2 FIGURES Figure No. Title Figure 6.2-1 Sh. 1 Safety Injection System - Flow Diagram, Sheet 1 - Replaced with Plant Drawing 9321-2735 Figure 6.2-1 Sh. 2 Safety Injection System - Flow Diagram, Sheet 2-Replaced with Plant Drawing 235296 Figure 6.2-2 Primary Auxiliary Building Safety Injection System Piping-Schematic Plan Figure 6.2-3 Primary Auxiliary Building Safety Injection System Piping-Schematic Elevations Figure 6.2-4 Containment Building Safety Injection System Piping-Plan Figure 6.2-5 Containment Building Safety Injection System Piping-Elevation Figure 6.2-6 Safety Injection Pump Performance Figure 6.2-7 Residual Heat Removal Pump Performance Figure 6.2-8 Recirculation Pump Performance Figure 6.2-9 Deleted Cha pter 6, Page 56 of 170 Revision 20 OAG10000215_0765

IP2 FSAR UPDATE 6.3 CONTAINMENT SPRAY SYSTEM 6.3.1 Design Bases 6.3.1.1 Containment Heat Removal Systems Criterion: Where an active heat removal system is needed under accident conditions to prevent exceeding containment design pressure, this system shall perform its required function, assuming failure of any single active component. (GDC 52) Adequate containment heat removal capability for the containment is provided by two separate, full capacity, engineered safety feature systems. The containment spray system, whose components operate in the sequential modes described in Section 6.3.2, and the containment air recirculation cooling system, which is discussed in Section 6.4. The primary purpose of the containment spray system is to spray cool water into the containment atmosphere when appropriate in the event of a loss-of-coolant accident and thereby ensure that containment pressure does not exceed its design value, which is 47 psig at 271°F. (100-percent relative humidity) This protection is afforded for all pipe break sizes up to and including the hypothetical instantaneous circumferential rupture of a reactor coolant loop as discussed in UFSAR Section 14.3.5.1.1. Pressure and temperature transients for a loss-of-coolant accident are presented in Section 14.3. Although the water in the core after a loss-of-coolant accident is quickly subcooled by the safety injection system, the containment spray system design is based on the conservative assumption that the core residual heat is released to the containment as steam. Any of the following combinations of equipment will provide sufficient heat removal capability to maintain the postaccident containment pressure below the design value, assuming that the core residual heat is released to the containment as steam.

1. Containment Spray alone as follows:

Both containment spray pumps operating up to the time the transfer to core recirculation flow begins (during injection phase).
One spray pump continuing to take suction from the RWST until the level in the RWST decreases to 2 feet.
Both recirculation pumps (or both residual heat removal pumps), both residual heat exchangers and both containment recirculation spray headers in operation when the level in the RWST decreases below 2 feet.

2. All five containment cooling fans (to be discussed in Section 6.4).

3. One containment spray pump and three of the five containment cooling fans (the minimum containment safeguards case discussed in Section 14.3.5).

6.3.1.2 Inspection of Containment Pressure-Reducing Systems Criterion: Design provisions shall be made to the extent practical to facilitate the periodic physical inspection of all important components of the containment pressure-reducing systems, such as pumps, valves, spray nozzles and sumps. (GDC 58). Cha pter 6, Page 57 of 170 Revision 20 OAG10000215_0766

IP2 FSAR UPDATE Where practicable, all active components and passive components of the containment spray system are inspected periodically to demonstrate system readiness. The pressure-containing components are inspected for leaks from pump seals, valve packing, flanged joints, and safety valves. During operational testing of the containment spray pumps, the portions of the system subjected to pump pressure can be inspected for leaks. Design provisions for inspection of the safety injection system, which also function as part of the containment spray system, are described in Section 6.2.5. 6.3.1.3 Testing of the Containment Pressure-Reducing Systems Components Criterion: The containment pressure-reducing systems shall be designed, to the extent practical so that active components, such as pumps and valves, can be tested periodically for operability and required functional performance. (GDC 59) All active components in the containment spray system are adequately tested both in preoperational performance tests in the manufacturer's shop and inplace testing after installation. Thereafter, periodic tests are also performed as required after any component maintenance. Testing of the components of the safety injection system that are used for containment spray purposes is described in Section 6.2.5. The component cooling water pumps and the non-essential service water pumps that supply cooling water to the residual heat exchangers are in operation on a relatively continuous schedule during plant operation. Those pumps not running during normal operation may be tested by changing the operating pump(s). 6.3.1.4 Testing of Containment Spray Systems Criterion: A capability shall be provided to the extent practical to test periodically the operability of the containment spray system at a position as close to the spray nozzles as is practical. (GDC 60) Permanent test lines for the containment spray loops are located so that all components up to the containment isolation valves upstream of the spray nozzles may be tested. These isolation valves and spray nozzles are tested separately. Each spray pump is provided with a recirculation line from the pump discharge line back to the pump suction line with a globe valve to allow greater flow through the pump during surveillance testing of the pump. An ultrasonic flow instrument is installed on each recirculation line during testing to allow resetting of the globe valve, after testing to the original flow value of the eductor (112 gpm). Note the globe valve replaced the eductor. Temporary test connections, downstream of the isolation valves, are provided to verify that spray nozzles are not obstructed. Air flow through the nozzles will be monitored by means of the helium-filled balloon method, or by using an infrared scanning technique. 6.3.1.5 Testing of Operational Sequence of Containment Pressure-Reducing Systems Criterion: A capability shall be provided to test initially under conditions as close as practical to the design and the full operational sequence that would bring the containment pressure reducing systems into action, including the transfer to alternate power sources. (GDC 61) Cha pter 6, Page 58 of 170 Revision 20 OAG10000215_0767

IP2 FSAR UPDATE Capability is provided to test initially to the extent practical the operational startup sequence of the containment spray system including the transfer to alternative power sources. 6.3.1.6 Performance Objectives The containment spray system is designed to spray at least 5000 gpm of borated water into the containment whenever the coincidence of two sets of two out of three (Hi-Hi) containment pressure (approximately 50-percent of design value) signals occur or when a manual signal is initiated. Either of two subsystems containing a pump and associated valving and spray header is independently capable of delivering one-half of the designed flow, or 2500 gpm, which exceeds the minimum containment spray flow of 2180 gpm assumed in the Containment Analysis as described in Table 14.3-40. The design basis for the containment spray system is, full capacity flow will provide sufficient heat removal capability to maintain the post accident containment pressure below 47 psig, assuming that the core residual heat is released to the containment as steam. A second purpose served by the containment spray system is to remove elemental iodine and particulates from the containment atmosphere should they be released in the event of a loss-of-coolant accident. The analysis, indicating the system's ability to limit the offsite dose to within applicable limits after a hypotheticalloss-of-coolant accident is presented in Section 14.3.6. To meet the above bases, the following design requirements were established:

1. All components of the system have to meet Class I seismic criteria.

2. The system's initial response has to be fully automatic.

3. Total redundancy of equipment, flow paths, and power supply.

4. Provisions for periodic testing have to be provided.

5. Equipment is to be arranged to provide maximum protection from missiles.

The spray system, including recirculation spray, is designed to operate over an extended time period following a reactor coolant system failure, as required to restore and maintain containment conditions at or near atmospheric pressure. It has the capability of reducing the containment postaccident pressure and subsequent containment leakage. A tertiary function of the system is to provide an alternative means of filling the reactor refueling cavity during reactor vessel head removal. Portions of other systems that share functions and become part of the containment spray system, when required, are designed to meet the criteria of the containment cooling function. Neither a single active component failure in such systems during the injection phase nor an active/passive failure during the recirculation phase will degrade the design heat removal capability of containment cooling. System piping located within the containment is redundant and separable in arrangement unless fully protected from damage that may follow any reactor coolant system loop failure. Cha pter 6, Page 59 of 170 Revision 20 OAG10000215_0768

IP2 FSAR UPDATE System isolation valves relied upon to operate for containment cooling are redundant with automatic actuation. 6.3.1.7 Service Life All portions of the system located within containment are designed to withstand, without loss of functional performance, the postaccident containment environment and to operate without benefit of maintenance for the duration of time required to restore and maintain containment conditions at near atmospheric pressure. The recirculation pumps are designed to be operable for 1 yr following a loss-of-coolant accident. 6.3.1.8 Codes and Classifications Table 6.3-1 tabulates the codes and standards to which the containment spray system components are designed. 6.3.2 System Design And Operation 6.3.2.1 System Description Adequate containment cooling and iodine removal by the containment spray system are provided by system components operating in sequential modes. These modes are:

1. Spray a portion of the contents of the refueling water storage tank into the entire containment atmosphere using the containment spray pumps.

2. Recirculation of water from the containment sump by the diversion of a portion of the recirculation flow from the safety injection system to the spray headers inside the containment after injection from the refueling water storage tank has been terminated.

The bases for the selection of the various conditions requiring system actuation are presented in Section 14.3. The system diagram for the containment spray system is shown in Plant Drawings 9321-2735 & 235296 [Formerly UFSAR Figure 6.2-1]. The principal components of the containment spray system that provide containment cooling and iodine removal following a loss-of-coolant accident consist of two spray pumps, trisodium phosphate baskets located in containment, spray ring headers and nozzles, and the necessary piping and valves. The containment spray pumps are located in the primary auxiliary building and the spray pumps take suction directly from the refueling water storage tank. The containment spray system also uses the two 100-percent capacity recirculation pumps, two residual heat removal heat exchangers and associated valves and piping of the safety injection system for the long-term recirculation phase of containment cooling and iodine removal after the refueling water storage tank has been exhausted. The spray water is injected into the containment through spray nozzles connected to four 360 degree ring headers located in the containment dome area. Each of the spray pumps supplies two of the ring headers. Cha pter 6, Page 60 of 170 Revision 20 OAG10000215_0769

IP2 FSAR UPDATE 6.3.2.1.1 Injection Phase Containment spray will be actuated by two sets of coincidence logic circuits each requiring two-out-of-three, high-high containment pressure signals. This starting signal will start the pumps and open the discharge valves to the spray header. 6.3.2.1.2 Recirculation Phase When the refueling water storage tank level drops below 2 feet and its contents have been added to the containment floor, recirculation spray flow will be initiated since the NPSH requirements for the recirculation pumps are met for the additional flow needed for combined core injection and recirculation spray. The operator can remotely open the stop valves on either of the two spray recirculation lines. With this split flow, decay heat can be removed and containment airborne activity reduced. This mode of operation will be continued for a period of at least 3.4 hr following the accident in order to continue removal of airborne activity from the containment atmosphere. After the 3.4 hr containment scrubbing operation it is expected that spray flow would be discontinued while maintaining containment pressure with the containment fan-cooler units, and returning all of the recirculated water to the core. In this mode, the bulk of the core residual heat is transferred directly to the sump by the spilled coolant to be eventually dissipated through the residual heat removal heat exchanger once the sump water becomes heated. The heat removal capacity of three of the five fan coolers is sufficient to remove the corresponding energy addition to the vapor space as a result of steam boiloff from the core, assuming flow into the core from one recirculation pump at the termination of injection spray without exceeding containment design pressure; hence, it is not expected that continued spray operation for containment heat removal would be required. If, however, the containment pressure was observed to increase, then recirculation to the spray header may be resumed by operator action as described above. Trisodium phosphate is stored at elevation 46' inside the containment building. During the injection phase the level of the boric acid solution from the containment spray and the coolant lost from the reactor coolant system will rise above the trisodium phosphate bins. The trisodium phosphate will dissolve into the solution, providing a solution with pH in the range of 7 to 9.5 to enhance long-term iodine retention in the solution and to minimize corrosion. 6.3.2.1.3 Cooling Water The cooling water for the residual heat exchangers has been described in Section 6.2. 6.3.2.1.4 Changeover The sequence for the changeover from injection to recirculation has been described in Section 6.2. Remote-operated valves of the containment spray system that are under manual control (that is, valves that normally are in their ready position and do not receive a containment spray signal) have their positions indicated on a common portion of the control board. At any time during operation when one of these valves is not in the ready position for injection, an audible and visual annunciation is provided on the board to alert the operator of this condition. Chapter 6, Page 61 of 170 Revision 20 OAG10000215_0770

IP2 FSAR UPDATE 6.3.2.2 Components All associated components, piping, structures, and power supplies of the containment spray system are designed to Class I seismic criteria. All components inside containment are capable of withstanding or are protected from differential pressures that may occur during the rapid pressure rise to 47 psig in 10 sec. Section 14.3.5.1.1 discusses the analyses that show that the calculated postaccident containment pressures are less severe than this. The lines of the system are protected from missile damage by the concrete crane wall and operating floor. Parts of the system in contact with the spray solution are stainless steel or an equivalent corrosion-resistant material. The containment spray system shares the refueling water storage tank capacity with the safety injection system. For a detailed description of this tank, see Section 6.2. 6.3.2.2.1 Pumps The two containment spray pumps are of the horizontal centrifugal type driven by electric motors. The design head of the pump is sufficient to continue at rated capacity, with a minimum level in the refueling water storage tank, against a head equivalent to the sum of the design pressure of the containment, the head to the uppermost nozzles, and the line and nozzle pressure losses. Pump motors are direct-coupled and large enough for maximum power requirement of the pump. The materials of construction, which are suitable for use with the spray solutions, are stainless steel or equivalent corrosion-resistant material. Design parameters are presented in Table 6.3-2 and the containment spray pump characteristics are shown on Figure 6.3-1. The containment spray pumps are designed in accordance to the specifications discussed for the pumps in the safety injection system, Section 6.2. The recirculation pumps of the safety injection system, which provide flow to the containment spray system during the recirculation phase, are described in Section 6.2. Details of the component cooling pumps and service water pumps, which serve the safety injection system, are presented in Sections 9.3 and 9.6. 6.3.2.2.2 Heat Exchangers The two residual heat removal heat exchangers of the safety injection system, which are used during the recirculation phase, are described in Section 6.2. 6.3.2.2.3 Spray Nozzles The spray nozzles, which are of the hollow cone, ramp bottom design, are not subject to clogging by particles 0.25-in. in maximum dimension, and are capable of producing a surface area averaged drop diameter of approximately 1000 microns at 15 gpm and 40 psi differential Cha pter 6, Page 62 of 170 Revision 20 OAG10000215_0771

IP2 FSAR UPDATE pressure. With the spray pump operating at design conditions and the containment at design pressure the pressure drop across the nozzles will exceed 40 psi. on the water is screene~throLlghJh~$I$g"di~m@t§dhQI@§Qf

                                """"""~""""" before leaving the r~qirq@I1l~QnQr containment sump. The spray nozzles are stainless steel and have a 0.375-in. diameter orifice. The nozzles are connected to four 360 degree ring headers (alternating headers connected) of radii 7-ft 1.75-in.

(EI. 228.5-ft), 25-ft 3.438-in. (EI. 223.5-ft), 42-ft 3-in. (EI. 218.5-ft) and 59-ft 6-in. (EI. 213.5-ft). There are 315 nozzles distributed on the four headers. This nozzle and header arrangement results in maximum area coverage with either branch of the system operating alone, while ensuring minimum overlap of spray trajectories in the minimum flow case (Section 14.3). 6.3.2.2.4 Spray Additive Tank The spray additive tank has been removed based on the use of trisodium phosphate baskets described in Section 6.3.2.2.12. 6.3.2.2.5 Spray Pump Recirculation Line Each spray pump is provided with a recirculation line from the pump discharge line back to the pump suction line. A globe valve is installed in this line to allow setting of the desired flow rate for both on line and testing configurations. 6.3.2.2.6 Valves The valves for the containment spray system are designed in accordance with the specifications discussed for the valves in the safety injection system (Section 6.2). 6.3.2.2.7 Piping The piping for the containment spray system is designed in accordance to the specifications discussed for the piping in the safety injection system (Section 6.2). The system is designed for 150 psig at 300°F on the suction side and 300 psig at 300°F on the discharge side of the spray pumps. 6.3.2.2.8 Motors for Pumps and Valves The motors inside and outside containment for the containment spray system are designed in accordance with the specifications discussed for motors in the safety injection system (see Section 6.2). 6.3.2.2.9 Electrical Supply Details of the normal and emergency power sources are presented in the discussion of the electrical system, Chapter 8. 6.3.2.2.10 Missile Protection The spray headers are located outside and above the reactor and steam generator concrete shields. A shield, which is removable for refueling also provides missile protection for the area Cha pter 6, Page 63 of 170 Revision 20 OAG10000215_0772

IP2 FSAR UPDATE immediately above the reactor vessel. The spray headers are therefore protected from missiles originating within the reactor coolant system. 6.3.2.2.11 Material Compatibility Parts of the system in contact with the spray solutions are stainless steel or an equivalent corrosion-resistant material. An analysis of materials compatibility with the long-term storage conditions of concentrated sodium hydroxide is presented in Appendix 60. Appendix 60 is being retained for historical purposes. All exposed surfaces within the containment have coatings that will not be affected by short term exposure to low pH containment spray solution or to long term exposure to high pH solution. An analysis of the materials exposed to the Post-accident Containment Environment using the original containment spray additive (NaOH) solution is presented in Appendix 6C. Post-accident chemistry changes due to the elimination of the spray additive tank and the installation of Trisodium Phosphate Baskets were evaluated and it was determined that this change has little effect on the compatibility of materials located in containment, which will come in contact with the initial spray and recirculation spray solution. This evaluation is documented in Reference 2. This evaluation supersedes the information contained in Appendix 6C, with the exception of sections 6C.4.1, and 6C.7. Therefore, with these exceptions, Appendix 6C is being retained for historical purposes. Maintaining the long-term pH of the recirculated ECC solution no less than 7.0, prevents chloride-induced stress corrosion cracking of austenitic stainless steel components, and minimizes hydrogen produced by the corrosion of galvanized surfaces and zinc-based paints as discussed in Reference 1. These chemistry changes also do not affect the environmental qualification of equipment located within the containment required to mitigate the consequences of design basis accidents as discussed in Section 7.1.4. 6.3.2.2.12 Trisodium Phosphate Baskets Trisodium phosphate (TSP) is stored in four baskets at elevation 46' in the containment building. During the injection phase the baskets will be flooded, allowing the TSP to dissolve into the fluid for pH control. The four baskets are constructed of stainless steel and are seismically qualified and mounted. 6.3.3 Design Evaluation 6.3.3.1 Range of Containment Protection For the first 15 to 20 min following the maximum loss-of-coolant accident (i.e., during the time that the containment spray pumps take their suction from the refueling water storage tank), this system provides the design heat removal capacity for the containment. After the injection phase, one spray pump continues to take suction from the RWST and spray into the containment until RWST level drops below 2 feet. This continued spray injection is sufficient to maintain the containment pressure below the design value even if no containment fans were operating. With the completion of containment spray injection the operator sets up recirculation to one spray header and to the core; the systems are aligned so that sufficient cooled recirculated water is delivered to keep the core flooded as well as to provide flow to one spray header. Flow is maintained to the spray header at this stage primarily to continue scrubbing of airborne Cha pter 6, Page 64 of 170 Revision 20 OAG10000215_0773

IP2 FSAR UPDATE activity, i.e., for at least 3.4 hr after the accident; the flow, however, is also sufficient to maintain the containment pressure below the design value. Any of the following combinations of equipment will provide sufficient heat removal capability to maintain the post-accident containment pressure below the design value, assuming that the core residual heat is released to the containment as steam.

1. Containment Spray alone as follows:

Both containment spray pumps operating up to the time the transfer to core recirculation flow begins (during injection phase). One spray pump continuing to take suction from the RWST until the level in the RWST decreases to 2 feet. Both recirculation pumps (or both residual heat removal pumps), both residual heat exchangers and both containment recirculation spray headers in operation when the level in the RWST decreases below 2 feet.

2. All five containment cooling fans (discussed in Section 6.4)

3. One containment spray pump and three of the five containment cooling fans (the minimum containment safeguards case discussed in Section 14.3.5).

During the injection and recirculation phases the spray water is raised to the temperature of the containment in falling through the steam-air mixture. The minimum fall path of the droplets is approximately 118-ft from the lowest spray ring headers to the operating deck. The actual fall path is longer due to the trajectory of the droplets sprayed out from the ring header. Drops of approximately 1000 micron average size will reach temperature equilibrium with the steam-air containment atmosphere after falling through less than half the available spray fall height as discussed in UFSAR Section 14.3.5.2.1. At containment design temperature, 271°F, the total design heat absorption capability of one spray pump is 218 x 106 Btu/hr based on the assumption of 100°F refueling water and design flow of 2500 gpm. When the refueling water storage tank level drops below 2 feet, injection spray is terminated and the recirculation pumps supply the flow to the containment recirculation spray headers. Recirculation spray can be established at a flow rate that will maintain containment pressure below the design pressure of 47 psig even if no containment fan coolers are operating. Elemental iodine and aerosols are removed by the containment spray system. Removal coefficients and the limitations on removal are discussed in Appendix 6A. A discussion of the effectiveness of containment spray as a fission product trapping process is contained in Reference 1. A single train of containment spray will provide sufficient iodine removal capability to ensure postaccident fission product leakage that would not result in exceeding the applicable dose limits. This is evaluated in Section 14.3.6. Cha pter 6, Page 65 of 170 Revision 20 OAG10000215_0774

IP2 FSAR UPDATE 6.3.3.2 System Response The starting sequence of the containment spray pumps and their related emergency power equipment is discussed in sections 7.2 and 8.2.3.4 and their analyzed performance is discussed in the various Chapter 14 safety analyses. 6.3.3.3 Single Failure Analysis A failure analysis has been made on all active components of the system to show that the failure of any single active component will not prevent fulfilling the design function. This analysis is summarized in Table 6.3-4. In addition, each spray header is supplied from the discharge from one of the two residual heat removal heat exchangers. As described in Section 6.2.2.1.2, these two heat exchangers are redundant and can be supplied with recirculated water via separate and redundant flow paths. The analysis of the loss-of-coolant accident presented in Section 14.3 reflects the single failure analysis. 6.3.3.4 Reliance on Interconnected Systems For the injection phase, the containment spray system operates independently of other engineered safety features following a loss-of-coolant accident except that it shares the source of water in the refueling water storage tank with the safety injection system. The system acts as a backup for the cooling function of the containment air recirculation cooling system. For extended operation in the recirculation mode, water is supplied through recirculation pumps. During the recirculation phase, some of the flow leaving the residual heat removal heat exchangers may be diverted to the containment spray headers or the high-head safety injection pumps. Minimum flow requirements are established for the flow being sent to the core and for the flow being sent to the containment spray. Sufficient flow instrumentation is provided so that the operator can monitor each flow path as shown in Plant Drawings 9321-2735 & 235296 [Formerly UFSAR Figure 6.2-1]. Normal and emergency power supply requirements are discussed in Chapter 8. 6.3.3.5 Shared Functions Evaluation Table 6.3-5 contains an evaluation of the main components that have been discussed previously and a brief description of how each component functions during normal operation and during the accident. 6.3.3.6 Containment Spray Pump Net Positive Suction Head Requirements The net positive suction head for the containment spray pumps is evaluated for injection operation. The end of the injection phase gives the limiting net positive suction head requirement. The net positive suction head available is determined from the elevation head and vapor pressure of the water in the refueling water storage tank, and the pressure drop in the piping to the pump. At the end of the injection phase, the net positive suction head available exceeds the net positive suction head required. Cha pter 6, Page 66 of 170 Revision 20 OAG10000215_0775

IP2 FSAR UPDATE 6.3.4 Minimum Operating Conditions The Technical Specifications establish limiting conditions regarding the operability of the system. 6.3.5 Inspections And Tests 6.3.5.1 Inspections All components of the containment spray system may be inspected periodically to demonstrate system readiness. The pressure-containing systems can be inspected for leaks from pump seals, valve packing, flanged joints, and safety valves during system testing. During the operational testing of the containment spray pumps, the portions of the system subjected to pump pressure can be inspected for leaks. 6.3.5.2 Preoperational Testing The principal components of the containment spray system are two pumps, spray ring headers and nozzles, and the necessary piping and valves. In discussing preoperational testing and generally proving that the system meets the design specification, it is necessary to consider both individual component testing and onsite testing. 6.3.5.2.1 Offsite Test Work Three components in the system were subjected to offsite test work:

1. Spray pumps - The spray pumps were subjected to conventional acceptance tests and the performance characteristic was plotted to illustrate the pumps met the design specification.

2. Spray nozzles - As part of the development work in support of Westinghouse Plants, a nozzle of the type used in the spray system was subjected to a performance test to demonstrate and prove the nozzle characteristic, e.g.,

flow/pressure drop, droplet size, spread of spray, etc. As part of the quality assurance program, a random 25-percent of the nozzles installed at the Indian Point Unit 2 site were given a general performance test. 6.3.5.2.2 Onsite Test Work The aim of onsite preoperational testing was to:

1. Demonstrate and prove that the system is adequate to meet the design pressure conditions. Outside the containment, this involved partial radiographic inspection and partial hydro-testing; inside the containment, the spray headers were subjected to 100-percent radiographic inspection.

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2. Demonstrate that the spray nozzles in the containment spray header are clear of obstructions by passing air through the test connections.

3. Verify that the proper sequencing of valves and pumps occurs on initiation of the containment spray signal and demonstrate the proper operation of all remotely operated valves

4. Verify the operation of the spray pumps; each pump was run at shutoff and the mini-flow directed through the normal path back to the refueling water storage tank. During this time, the mini-flow was adjusted to that required for routine testing.

5. Demonstrate the operation of the spray eductors. The eductor and spray additive system was checked by running, in turn, each spray pump on mini-flow with the spray additive tank filled with water and open to the spray eductor suction. During draindown of the spray additive tank, the tank level and corresponding eductor suction flow was recorded via the system instrumentation.

Finally, the system performance with water was extrapolated to that with sodium hydroxide, and the adequacy of the system thus verified. In order to establish a reference eductor suction test flow for routine testing of the system, the above test was made with the spray additive tank isolated and the eductor drawing water through the refueling water storage tank/eductor suction test line. 6.3.5.2.3 System Testing The functional test of the injection system described in Section 6.2.5 demonstrates proper transfer to the emergency diesel generator power source in the event of a loss of power. A test signal simulating the containment spray signal is used to demonstrate the operation of the spray system up to the isolation valves on the pump discharge. The isolation valves are blocked closed for the test. These isolation valves are checked separately. 6.3.5.3 Postoperational Testing 6.3.5.3.1 Component Testing Routine periodic testing of the containment spray system components and all necessary support systems at power is performed. When testing indicates a need for corrective maintenance, the redundancy of equipment in these systems permits such maintenance to be performed without shutting down or reducing load under conditions defined in the Technical Specifications. These conditions would include such matters as the period within which the component should be restored to service and the capability of the remaining equipment to meet safety limits within such a period. 6.3.5.3.2 Routine Inservice Testing The aim of the periodic test is: Cha pter 6, Page 68 of 170 Revision 20 OAG10000215_0777

IP2 FSAR UPDATE

1. To verify that the proper sequencing of valves and pumps occurs on initiation of the containment spray signal and demonstrate the proper operation of all remotely operated valves.

2. To verify the operation of the spray pumps; each pump will be run at shutoff and the mini-flow directed through the normal path back to the refueling water storage tank.

During these tests the equipment can be visually inspected for leaks, leaking seals, or packing; or flanges are tightened to eliminate the leak, and valves and pumps operated and inspected after any maintenance to ensure proper operation. 6.3.5.3.3 System Testing The post operational testing of the safety injection system is described in Section 6.2.5. Section 8.5 describes the testing required to demonstrate proper transfer to the emergency diesel-generator power source in the event of a loss of power. REFERENCES FOR SECTION 6.3

1. Letter from Jefferey F. Harold, NRC, to Stephen E. Quinn, Con Edison,

Subject:

Issuance of Amendment No. 191 for Indian Point Nuclear Generating Unit No.2, dated April 23,1997

2. "Elimination of the Emergency Containment Filtration and Spray Additive Systems from Indian Point Nuclear Generating Station Unit No.2" WCAP-14542 (Westinghouse Non-Proprietary Class 3)

TABLE 6.3-1 Containment Spray System - Code Requirements Component Code Valves USAS B16-5 Piping (including headers and spray nozzles) USAS B31.1 Cha pter 6, Page 69 of 170 Revision 20 OAG10000215_0778

IP2 FSAR UPDATE TABLE 6.3-2 Containment Spray System Design Parameters Pumps Quantity 2 Design pressure, discharge, psig 300 Design pressure, suction, psig 150 Design temperature, of 150 Design flow rate, gpm 2600 Design head, ft 450 Maximum pump flow rate, gpm 3450 Shutoff head, ft 490 Motor, hp 400 Type Horizontal-centrifugal TABLE 6.3-3 DELETED TABLE 6.3-4 (Sheet 1 of 2) Single Failure Analysis - Containment Spray System Component Malfunction Comments and Conseguences A. Spray nozzles Clogged Large number of nozzles (315) renders clogging of a significant number of nozzles incredible. B. Pumps

1) Containment spray pump Fails to start Two provided. Evaluation based on operation of one pump in addition to three out of five containment cooling fans operating during injection phase.

2) Recirculation pump Fails to start Two provided. Evaluation based on operation of one pump in addition to three out of five containment cooling fans operating during recirculation phase.

3) Non-essential service water Fails to start Three provided. Operation of one pump during recirculation required.

4) Component Cooling Fails to start Three provided. Operation of one pump during recirculation required.

5) Auxiliary Component Cooling Fails to start Two provided. Operation of these pumps is Pump no longer required.

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IP2 FSAR UPDATE TABLE 6.3-4 (Sheet 2 of 2) Single Failure Analysis - Containment Spray System Component Malfunction Comments and Conseguences C. Automatically Operated Valves: (Open on coincidence of two -2/3 high containment pressure signals)

1) Containment spray pump Fails to open Two provided. Operation of one required.

discharge isolation valve

2) Isolation valve on component Fails to open Two parallel lines, one valve in either line is cooling water lines from required to open.

residual heat exchangers D. Valves operated from control room for recirculation

1) Containment sump Fails to open Two lines in parallel, one valve in either line recirculation isolation is required to open.

2) Containment spray header Fails to open Two valves provided. Operation of one isolation valve from residual required.

heat exchangers

3) Residual heat removal pump Fails to close Two valves in series, one required to close.

recirculation line

4) Residual heat removal pump Fails to close Two valves in series, one required to close discharge line (one valve is a check valve).

E. Automatically operated valves (Close from control room on injection to recirculation changeover)

1) Isolation valves at spray pump Fails to close Check valve in series with two parallel discharge valves provided. Operation of one of the two valve arrangement series required.

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IP2 FSAR UPDATE TABLE 6.3-5 Shared Functions Evaluation Component Normal Normal Accident Accident Operating Operating Function Arrangement Function Arrangement Containment None Lined up to Supply spray Lined up to Spray Pumps spray headers water to spray headers (2) containment atmosphere NOTE: Refer to Section 6.2 for a brief description of the refueling water storage tank, recirculation pumps, non-essential service water pumps, component cooling pumps, residual heat exchangers, component cooling heat exchangers and the auxiliary component cooling pumps, which are also associated either directly or indirectly with the containment spray system. 6.3 FIGURES Title Containment S 6.4 CONTAINMENT AIR RECIRCULATION COOLING SYSTEM 6.4.1 Design Basis 6.4.1.1 Containment Heat Removal Systems Criterion: Where an active heat removal system is needed under accident conditions to prevent exceeding containment design pressure, this system shall perform its required function, assuming failure of any single active component. (GDC 52) Adequate heat removal capability for the containment is provided by two separate, full capacity, engineered safety features systems. These are the containment spray system, whose components are described in Sections 6.2 and 6.3 and the containment air recirculation cooling and filtration system, whose components operate as described in Section 6.4.2. These systems are of different engineering principles and serve as independent backups for each other. Together these two systems provide the single failure protection for the containment cooling function as analyzed in Chapter 14. The containment air recirculation cooling system is designed to recirculate and cool the containment atmosphere in the event of a loss-of-coolant accident and thereby ensure that the containment pressure will not exceed its design value of 47 psig at 271°F (100-percent relative humidity). Although the water in the core after a loss-of-coolant accident is quickly subcooled by the safety injection system, the containment air recirculation cooling system is designed on a conservative assumption that the core residual heat is released to the containment as steam. Cha pter 6, Page 72 of 170 Revision 20 OAG10000215_0781

IP2 FSAR UPDATE Any of the following combinations of equipment will provide sufficient heat removal capability to maintain the postaccident containment pressure below the design value, assuming that the core residual heat is released to the containment as steam.

1. All five containment cooling fans.

2. Containment Spray alone as follows:

Both containment spray pumps operating up to the time the transfer to core recirculation flow begins (during injection phase). One spray pump continuing to take suction from the RWST until the level in the RWST decreases to 2 feet. Both recirculation pumps (or both residual heat removal pumps), both residual heat exchangers and both containment recirculation spray headers in operation when the level in the RWST decreases below 2 feet.

3. One containment spray pump and three of the five containment cooling fans (the minimum containment safeguards case discussed in Section 14.3.5).

6.4.1.2 Inspection of Containment Pressure-Reducing Systems Criterion: Design provisions shall be made to extent practical to facilitate the periodic physical inspection of all important components of the containment pressure-reducing systems, such as pumps, valves, spray nozzles, torus, and sumps. (GDC 58) Design provisions are made to the extent practical to facilitate access for periodic visual inspection of all important components of the containment air recirculation cooling system. 6.4.1.3 Testing of Containment Pressure-Reducing Systems Components Criterion: The containment pressure-reducing systems shall be designed to the extent practical so that components, such as pumps and valves, can be tested periodically for operability and required functional performance. (GDC 59) The containment air recirculation cooling system is designed to the extent practical so that the components can be tested periodically, and after any component maintenance, for operability and functional performance. A number of air recirculation and cooling units are normally in operation and no additional periodic tests are required. The service water pumps that supply the cooling units can be part flow-tested during plant operation via the installed bypass test loop. 6.4.1.4 Testing of Operational Sequence of Containment Pressure-Reducing Systems Criterion: A capability shall be provided to test initially under conditions as close as practical to the design and the full operational sequence that would bring the containment pressure-reducing systems into action, including the transfer to alternate power sources. (GDC 61) Cha pter 6, Page 73 of 170 Revision 20 OAG10000215_0782

IP2 FSAR UPDATE Means are provided to test initially to the extent practical the full operational sequence of the air recirculation system including transfer to alternative power sources. 6.4.1.5 Inspection of Air Cleanup Systems Criterion: Design provisions shall be made to the extent practical to facilitate physical inspection of all critical parts of containment air cleanup system, such as, ducts, filters, fans, and dampers. (GDC 62) Access is available for periodic visual inspection of the containment of recirculation cooling system components. 6.4.1.6 Testing of Air Cleanup Systems Components Criterion: Design provisions shall be made to the extent practical so that active components of the air cleanup systems, such as fans and dampers, can be tested periodically for operability and required functional performances. (GDC 63) The valves in a nonoperating unit can be periodically tested by actuating the controls and verifying deflection by instruments in the control room. A number of fans are normally in operation; no additional periodic fan tests are necessary. 6.4.1.7 Deleted 6.4.1.8 Deleted 6.4.1.9 Performance Objectives The containment ventilation system, discussed in Section 5.3, of which all of the components of the containment air recirculation cooling system are a part, is designed to remove the normal heat loss from equipment and piping in the reactor containment during plant operation and to remove sufficient heat from the reactor containment, following the initial loss-of-coolant accident containment pressure transient, to keep the containment pressure from exceeding the design pressure as discussed in Section 14.3.5. The fans and cooling units continue to remove heat after the loss-of-coolant accident and reduce the containment pressure close to atmospheric within the first 24 hr as discussed in Section 14.3.5.1.3. The fan-cooler units could operate continuously after the loss-of-coolant accident and are designed to be operable for 1 year. In addition to the design bases specified above, the following objectives are met to provide the engineered safety features functions:

1. The heat transfer rate that is assigned to the currently installed fan-cooler units under accident conditions is shown in Figures 14.3-1048 and 14.3-1040. The establishment of basic heat transfer design parameters for the cooling coils of fan cooler units are discussed in Section 14.3.5.2.2. Among the topics covered are selection of the tube-side fouling factor, effect of air-side pressure drop, effect of moisture entrainment in the air steam mixture entering the fan coolers, and calculation of the various air-side to water-side heat transfer resistances.

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2. In removing heat at the design basis rate, the coils are capable of discharging the resulting condensate without impairing the flow capacity of the unit and without raising the exit temperature of the service water to the boiling point. Since condensation of water from the air-steam mixture is the principal mechanism for removal of heat from the postaccident containment atmosphere by the cooling coils, the coil fins will operate as wetted surfaces under these conditions.

Entrained water droplets added to the air-steam mixture, such as by operation of the containment spray system, will therefore have essentially no effect on the heat removal capability of the coils.

3. Each of the five air-handling units is equipped with moisture separators rated for full unit flow.

In addition to the above design bases, the equipment was originally specified to be capable of withstanding, without impairing operability, a pressure of 70.5 psig and 298°F for a period of one hour. The motors were further specified to be capable of running for 48 hours at required fan load in an atmosphere consisting of an air water vapor mixture initially at 47 psig and 271°F, and of continuous operation at 10 psig and 175°F. These ambient conditions and operating times have been updated and are maintained by the ongoing Environmental Qualification Program discussed in Section 7.1.4. As part of this program, the fan motors are qualified to withstand containment environment conditions following the loss of coolant accident so that the fans can perform their required function during the recovery period (1 year). All components are capable of withstanding or are protected from differential pressures that may occur during the rapid pressure rise to 47 psig in 10 sec. Section 14.3.5.1.1 discusses the analyses that show that the calculated postaccident containment pressures are less severe than this. Portions of other systems that share functions and become part of this containment cooling system when required are designed to meet the criteria of the containment cooling function. Neither a single active component failure in such systems during the injection phase nor an active/passive failure during the recirculation phase will degrade the heat removal capability of containment cooling. Where portions of these systems are located outside of containment, the following features are incorporated in the design for operation under postaccident conditions:

1. Means for isolation of any section.

2. Means to detect and control radioactivity leakage into the environs.

6.4.2 System Design And Operation The flow diagram of the containment air recirculation cooling system is shown in Plant Drawing 9321-4022 [Formerly UFSAR Figure 5.3-1]. Individual system components and their supports meet the requirement for seismic Class structures and each component is mounted to isolate it from fan vibration. Chapter 6, Page 75 of 170 Revision 20 OAG10000215_0784

IP2 FSAR UPDATE 6.4.2.1 Containment Cooling System Characteristics The air recirculation system consists of five 20-percent capacity air-handling units, each including motor, fan, cooling coils, moisture separators, roughing filters, duct distribution system, instrumentation, and controls. The units are located on the intermediate floor between the containment wall and the primary compartment shield walls. The air recirculation system has a total heat removal capability of at least 308.5 MBtu/hr under conditions following a loss-of-coolant accident and at a service water temperature of 95°F. Each fan is designed to supply 65,000 cfm at approximately 22.8-in. static pressure, 271°F, 0.175 Iblfe density. The fans are direct-driven, centrifugal type, and the coils are plate fin-tube type. Air-operated, tight-closing, 125 psi USAS butterfly valves isolate any inactive air-handling unit from the duct distribution system. Ductwork distributes the cooled air to the various containment compartments and areas. During normal and accident operation, the flow sequence through each air-handling unit is as follows: cooling coils, moisture separators, fan, discharge header. Roughing filters are installed up-stream of the cooling coils during plant cleanup and any time the reactor is down. These roughing filters are not in place during power operation. Plant Drawing 9321-4026 [Formerly UFSAR Figure 6.4-3] is an engineering layout drawing of an air-handling unit showing the arrangement of the above components in the unit. Plant Drawing 9321-2502 [Formerly UFSAR Figure 5.1-3] shows the location of the five units on the intermediate floor (elevation 68-ft-0-in.). 6.4.2.1.1 Actuation Provisions The butterfly valves have only two positions, full open and full closed. These valves are air operated and spring loaded. Upon loss of control signal or control air, the spring actuates the valve to the accident position (fail-safe operation). Upon either manual or automatic actuation of the safety injection safe-guards sequence, the butterfly valves are tripped to the accident position. Accident position is also the fail-safe position. Redundant, electrically operated, three-way solenoid valves are used with each butterfly valve to control the instrument air supply (control air). These valves are arranged so that failure of a single solenoid valve to respond to the accident signal will not prevent actuation of the butterfly valve to the accident position (fail-safe operation). The containment pressure is sensed by eight separate pressure transmitters (six of which are used to generate automatic actuation signals) located outside the containment. Containment pressure is communicated to the transmitters through three %-in. stainless steel lines penetrating the containment vessel. A high containment pressure signal automatically actuates the safety injection safeguard sequence (reference is made to Section 6.2.2), which trips the valves to the accident position. Two high-range containment pressure transmitters have been installed in response to NUREG-0737. These transmitters allow for the indication and recording of pressure up to 150 psig. These signals are recorded on two independent recorders located on the accident assessment Cha pter 6, Page 76 of 170 Revision 20 OAG10000215_0785

IP2 FSAR UPDATE panel in the common Unit 1/Unit 2 central control room. The fans are part of the engineered safety features and either all five, or at least three of five fans will be started after an accident, depending on the availability of emergency power. (Reference is made to Section 8.2.) Overload protection for the fan motors is provided at the switchgear by overcurrent trip devices in the motor feeder breakers. The breakers can be operated from the control room and can be reclosed from the control room following a motor overload trip. Flow switches in the ductwork system, operating both normally and after an accident, indicate whether air is circulating in accordance with the design arrangement. Abnormal flow alarms are provided in the control room. 6.4.2.1.2 Flow Distribution and Flow Characteristics The location of the distribution ductwork outlets, with reference to the location of the air-handling unit return inlets, ensures that the air will be directed to all areas requiring ventilation before returning to the units. The arrangement is shown in Plant Drawing 9321-4022 [Formerly UFSAR Figure 5.3-1]. In addition to ventilating areas inside the periphery of the shield wall, the distribution system also includes two branch ducts located at opposite extremes of the containment wall for ventilating the upper portion of the containment. These ducts are provided with nozzles and extend upward along the containment wall as required to permit the throw of air from nozzles to reach the dome area and ensure that the discharge air will mix with the atmosphere. The air discharge inside the periphery of the shield wall will circulate and rise above the operating floor through openings around the steam generators where it will mix with air displaced from the dome area. This mixture will return to the air-handling units through floor gratings located at the operating floor directly above each air-handling unit inlet. The temperature of this air will be essentially the ambient existing in the containment vessel. The steam-air mixture from the containment entering the cooling coils during the accident will be at approximately 271°F and have a density of 0.175 Ib/fe. Part of the water vapor condenses on the cooling coil and is collected by the condensate trays. The condensate from the trays is directed below to the floor tray by means of an individual piping system. The condensate collection and drain system is important to the proper functioning of the cooling coils. The air leaving the unit thus will be saturated at a temperature slightly below approximately 265°F. The fluid will leave the cooling coils and enter the moisture separators at approximately 265°F and saturated (100-percent relative humidity) condition. The purpose of the moisture separators is to remove the entrained moisture. The fluid will remain in this condition as it flows through the fan, but will pick up some sensible heat from the fan and fan motor before flowing into the distribution header. This sensible heat will increase the dry-bulb temperature slightly above 265°F and will decrease the relative humidity slightly below 100-percent. With a flow rate of approximately 65,000 cfm from each fan under accident conditions and the containment free volume of 2,610,000-fe, the recirculation rate with five fans operating is approximately 7.5 containment volumes per hour. 6.4.2.1.3 Deleted Cha pter 6, Page 77 of 170 Revision 20 OAG10000215_0786

IP2 FSAR UPDATE 6.4.2.1.4 Cooling Water for the Fan-Cooler Units The cooling water requirements for all five fan-cooling units during a major loss-of-primary-coolant accident and recovery are supplied by two of the three nuclear service water pumps. The service water system is described in Section 9.6. The cooling water discharge from the fan and motor cooling coils flows to the discharge canal. As a protective measure a sample of the effluent from these coils is monitored for radioactivity. The sample from the coils is monitored by two redundant radiation monitors. Upon indication of radioactivity in the effluent, each cooler discharge line is monitored individually to locate the defective cooling coil, which when identified would be isolated and operation would continue with the remaining units. The service water system pressure at locations inside the containment in the incident mode system alignment (which the system automatically assumes following a safety injection signal) could be below the containment design pressure of 47 psig. However, since the cooling coils and service water lines are a completely closed system inside the containment, no contaminated leakage is expected into these units. Local indication of service water discharge temperature from each fan-motor heat exchanger, as well as a fan cooler unit combined outlet header temperature indicator, are provided in the pipe pen outside containment. A fan-motor heat exchanger combined discharge header flow indicator is also located in the pipe pen outside containment. Flow for each fan cooler unit is indicated in the control room. Abnormal flow alarms are provided in the control room. A permanent differential pressure indicator has been installed across the 10-in. inlet and outlet water headers of the fan cooling units for pressure drop measurements. During normal plant operation, flow through the cooling units can be throttled for containment temperature control purposes by a valve on the common discharge header from the cooling units. Two independent, full flow, isolation valves open automatically to bypass the control valve in the event of a safety injection signal. Both valves fail in the open position upon loss of air pressure and either valve is capable of passing the full flow required for all five fan cooling units. 6.4.2.1.5 Environmental Protection All system control and instrumentation devices required for containment accident conditions are located to minimize the danger of control loss due to missile damage. All fan parts, valve shaft and disk seating surfaces, and ducts in contact with the containment fluid are protected against corrosion. The fan motor enclosures, electrical insulation, and bearings are designed for operation during accident conditions. All of the air-handling units are located on the intermediate floor between the containment building and the primary containment shield wall. The distribution header and service water cooling piping are also located outside the shield wall. This arrangement provides missile protection for all components. Cha pter 6, Page 78 of 170 Revision 20 OAG10000215_0787

IP2 FSAR UPDATE 6.4.2.2 Components 6.4.2.2.1 Moisture Separators The moisture separators are designed to remove a minimum of 99.9-percent of the entrained water in the air-steam mixture entering the air-handling units following a loss-of-coolant accident. With an air entrained moisture content of 0.35 Ib H2 0/1000-fe, the water flow rate entering the moisture separator section is approximately 23 Ib/min and the moisture separator effluent has essentially zero moisture content. Each bank is designed for horizontal air flow and is composed of 40 elements. Each element or separator is 24-in. x 25-in. x 2-in. (minimum) thick and is mounted in a steel support frame. A steel drain trough is incorporated for each horizontal tier of separators to collect and remove the water that is recovered from the air steam. Further, the design enables the separators to be removed from the upstream side of the support frame. In order to prevent the bypass of air around the bank, airtight seals are provided between the floor, walls, plenum, and around the perimeter of each moisture separator. The tight seal is accomplished by gaskets, adhesive, and pressure-sealing tape, all of which can withstand a temperature of 300°. The thickness of the gaskets is 0.25-in. for the separator elements and 0.375-in. for the perimeter sealing of the support frame; they do not extend into the media area when installed. The moisture separator elements are of fire-resistant construction and consist of mats of fiberglass pads reinforced with stainless steel wire mesh. Nonstainless steel parts used in the construction are protected against corrosion by painting with one 3-mil shop coat of Carbo Zinc No. 11 or the equivalent. The separator frames are fabricated of type 304L stainless steel with welded joints. 6.4.2.2.2 Roughing Filters The roughing filters remove the large particles from the air stream before contact is made with the cooling coils. The roughing filters are in operation during plant cleanup and any time the reactor is down. These are efficient for removing large particles and under normal conditions they offer a resistance to air flow of 0.2-in. of water. As in the case for all components of the air-handling recirculating system, the bank is designed for horizontal air flow. The bank contains 40 filters, each of which has dimensions of 22.875-in. wide x 23.5-in. high x 2-in. thick. All other details of the mounting frame, sealing and materials of construction, other than the filters themselves, are the same as described for the moisture separators. The filter is of fire-resistant construction and the medium is fiber glassmat. 6.4.2.2.3 Humidity Detectors Located just upstream of each fan cooling unit is a humidity detector used to determine the dewpoint in containment. See Section 6.7 for further details. Cha pter 6, Page 79 of 170 Revision 20 OAG10000215_0788

IP2 FSAR UPDATE 6.4.2.2.4 [Deleted] 6.4.2.2.5 Fan Motor Units The five containment cooling fans are of the centrifugal, nonoverloading, direct-drive type. Each fan can provide a minimum flow rate of 65,000 cfm when operating against the system resistance of approximately 22.8-in. static pressure existing during the accident condition (0.175 Iblfe density, containment pressure of 47 psig, and temperature of 271°F). The reactor containment fan cooler motors are Westinghouse 9n§qhql?:§qppli~~R@+Wqqh~, totally enclosed water-cooled, 350 hp, induction type, three-phase, 60 cycles, 1200 rpm, 440-V with ample insulation margin. Significant motor details are as follows:

1. Insulation Class F (NEMA rated total temperature 155°C) Westinghouse Thermalastic g[

QI§t§§H(N§Mmn?t@~tqt?I~~mp@r§t~gr@1§Q~Q)$qhq@§PQ)(Jli~@. It is impregnated and coated to give a homogeneous insulation system that is highly impervious to moisture. Internal leads and the terminal box-motor interconnection are given special design consideration to ensure that the level of insulation matches or exceeds that of the basic motor C\I<:TC'"Tl

2. Heat Exchanger An air-to-water heat exchanger is connected to the motor to form an entirely enclosed cooling system. Air movement is through the heat exchanger and is returned to the motor. A flapper type vent relief valve permits incident ambient (increasing containment pressure) to enter the motor air system so the bearings will not be subjected to differential pressure. The cooling coil condensate drain line will enable pressure equalization by the motor heat exchanger as the containment pressure is reduced. Water connections are welded throughout and supply and discharge are common with the containment cooler water system, i.e., supplied from the nuclear service water header. The drain is piped to the containment cooler drain system.

3. Bearings The motors are equipped with high-temperature, grease-lubricated ball bearings as would be required if the bearings were subjected to incident ambient temperatures. Continuous bearing monitoring that will alarm in the control room is provided.

4. Conduit (Connection) Box The motor leads are brought out of the frame through a seal and into a sealed conduit box.

5. [Deleted]

Cha pter 6, Page 80 of 170 Revision 20 OAG10000215_0789

IP2 FSAR UPDATE 6.4.2.2.6 Charcoal Filter Housing Pressure Equalization The charcoal filter housing includes a hole on the external wall of the fan cooler unit. The hole remained after the spring-loaded damper and the charcoal filters were removed and the charcoal filter inlet and outlet dampers were blocked closed during the 2002 refueling outage. When containment pressure rapidly rises as a result of an accident condition, the hole will relieve air into the charcoal filter compartment so as to minimize the negative pressure differential across the walls of the charcoal filter unit. The hole will help minimize positive differential pressure (between containment and the charcoal filter compartment) that can occur as a result of relieving containment pressure during normal plant operation. 6.4.2.2.7 [Deleted] 6.4.2.2.S Cooling Coils - Original Plant Design This section describes the cooling coils provided as part of the original plant operation. The heat removal capability of the cooling coils was 76.32 x 106 Btu/hr per air-handling unit at saturation conditions (271°F, 47 psig). The design internal pressure of the coil was 150 psig at 300°F and the coils could withstand an external pressure of 70.5 psig at a temperature of 300°F without damage. Each recirculating unit consisted of 10 coil units mounted in two banks of five coils high. These banks were located one behind the other for horizontal series air flow and the tubes of the coil were horizontal. Each coil assembly consisted of the first bank having six rows of coils and the second bank having four rows of coils. Each bank contained four Westinghouse Sturtevant designation WC-3620S (36-in. high by 10S-in. long) coil, and one Westinghouse Sturtevant WC-3010S (30-in. high by 10S-in. long) coil. This latter coil was at the top and had 16.7-percent fewer tubes. The coils were stacked five high to a bank. The total coil assembly (two banks of coils) was 42-in. wide. There were 10 rows of tubes in the horizontal flow direction and a total of 116 rows of tubes in the vertical direction. Cooling water flow was 1/3 velocity through the first coil bank (six rows of tubes in the horizontal). Tube supports were provided on 15-in. center lines to permit free expansion and contraction of the tubes. Supply and return manifolds at each coil were 4-in. and 3-in. in diameter 90-10 copper-nickel schedule 40 pipe for each bank, respectively. Tubes were 0.0625-in. in diameter with 0.035-in. wall thickness. Each "U" tube contained six brazed joints and was expanded to copper plate fins, each .OOS-in. thick along its straight lengths. The original coils were fabricated of copper plate fins vertically oriented on cupro-nickel tubes. For normal operation, S fins/in. were required to remove 2,000,000 Btu/hr using 10S tubes. The original fan-motor heat exchangers had similar construction. Each tube had S passes and 1S brazed joints, was 0.625-in. in diameter and 0.049-in. wall thickness, and had manifold headers 2-in. in diameter. In 19S1, however, these coils were replaced by those of another manufacturer (CVI Corporation). These replacement coils are described in Section 6.4.2.2.9. Local indication of service water discharge temperature from each fan-motor heat exchanger, as well as a fan cooler unit combined outlet header temperature indicator, are provided in the pipe Cha pter 6, Page Sl of 170 Revision 20 OAG10000215_0790

IP2 FSAR UPDATE pen outside containment. A fan-motor heat exchanger combined discharge header flow indicator is also located in the pipe pen outside containment. Flow for each fan cooler unit is indicated in the control room. Alarms indicating abnormal service water flow and radioactivity are provided in the control room. Pressure taps to which a L1P meter can be attached or provided to allow measurements of service water pressure drops through the individual fan cooler units. This instrumentation is intended to indicate fouling in the river water side of the cooling coil. The coils are provided with drain pans and drain piping to prevent flooding during accident conditions. This condensate is drained to the containment sump. Reference is made to Section 6.7. Drain flow is measured by a level transmitter located in a standpipe containing a slotted weir. A level alarm and indication is provided in the control room. Actual discharge flow rate is determined by referring the level to a calibration curve for the weir or by use of the weir meter. If the drainage rate for all five units is nearly the same, it may be concluded that this water is condensate from the containment atmosphere. A particular unit with a high drainage rate with respect to the other units could be an indication of a leak in one of the cooling coils. 6.4.2.2.9 Cooling Coils - Modified Fan-cooler cooling coils and fan-motor heat exchangers were replaced during the 1980/1981 refueling outage. Two of these coils and two exchangers were replaced during the 1986 refueling outage, and the remaining three were replaced during the 1987 refueling outage. The modified (1980/1981) design for all cooling coils (fan cooler coils and motor heat exchangers) was changed to 90-10 copper-nickel (CuNi) water box headers with removable cover plates to allow for inservice inspection and maintenance. Water box headers were of bolted construction and consist of tubesheets, spacer sections, coverplates, and flanged elbows with gaskets for all mating surfaces. Perforated baffle plates, also of 90-10 coppernickel (CuNi) were installed at the water box inlet of each fan-cooler/motor cooler unit to provide a more even flow distribution through the cooling coils. All "U" tubes are of 0.049-in. wall thickness, "hair-pin" construction, and are rolled into a tubesheet. All brazed joints (approximately 1800) are eliminated in this modified design. The modified fan cooler cooling coil assemblies have two banks each with five coils. However, both banks now have six rows of tubes for each coil. The upper coils are still proportionally shorter than the rest. The coils and exchangers installed in 1986-87 are similar, but utilize larger titanium water boxes, AL6X tubes, and fully-captured "0" ring gaskets. The gasket material provided with the new cooling coils is ethylene propylene diene monomer. Evaluations performed on this type of material have included exposure to radiation levels of 2 x 108 rads over one year (postaccident). The results of these tests indicated that this gasket material retained its functional capability (no leaks under hydrostatic test pressure of 225 psig). Evaluation of the integrated radiation dose rate to the cooling coils is estimated to be 7.4 x 106 rads based on the guidelines set forth in NUREG-0588 at a power level of 2758 Mwt. Cha pter 6, Page 82 of 170 Revision 20 OAG10000215_0791

IP2 FSAR UPDATE 6.4.2.2.10 Ducting The ducts are designed to withstand the sudden release of reactor coolant system energy and energy from associated chemical reactions without failure due to shock or pressure waves by incorporation of dampers along the ducts, which open at slight overpressure of 5 psi or less. The ducts are designed and supported to withstand thermal expansion during an accident. Where flanged joints are used, joints are provided with gaskets suitable for temperatures to 300°F. Ducts are constructed of corrosion-resistant material. 6.4.2.2.11 [Deleted] 6.4.2.2.12 Electrical Supply Details of the normal and emergency power sources are presented in Chapter 8. Further information on the components of the containment air recirculation cooling system is given in Section 5.3. 6.4.3 Design Evaluation 6.4.3.1 Range of Containment Protection The containment air recirculation cooling system provides the design heat removal capacity for the containment following a loss-of-coolant accident assuming that the core residual heat is released to the containment as steam. The system accomplishes this by continuously recirculating the air-steam mixture through cooling coils to transfer heat from containment to service water. The performance of the containment recirculation cooling system for pressure reduction is discussed in Section 14.3. Any of the following combinations of equipment will provide sufficient heat removal capability to maintain the postaccident containment pressure below the design value assuming that the core residual heat is released to the containment as steam.

1. All five containment cooling fans.

2. Containment Spray alone as follows:

Both containment spray pumps operating up to the time the transfer to core recirculation flow begins (during injection phase). One spray pump continuing to take suction from the RWST until the level in the RWST decreases to 2 feet. Both recirculation pumps (or both residual heat removal pumps), both residual heat exchangers and both containment recirculation spray headers in operation when the level in the RWST decreases below 2 feet. Cha pter 6, Page 83 of 170 Revision 20 OAG10000215_0792

IP2 FSAR UPDATE

3. One containment spray pump and three of the five containment cooling fans (the minimum containment safeguards case discussed in Section 14.3.5).

Following a loss-of-coolant accident both the containment spray system and reactor containment fan cooler system are placed in operation for heat removal, and containment air recirculation. The containment spray system also provides fission product reduction. During the injection phase of the accident, a minimum of one spray pump and three of five fan coolers are in operation. The heat removal requirement for the design basis accident are met with these minimum requirements during both the injection and recirculation phase. Section 14.3.5 discusses the pressure transient and heat removal capability of using minimum safeguards. Since the spray is effective in removal of inorganic iodine during the first 3.4 hr period following the accident, the spray flow could be terminated (subsequent to 3.4 hr) after the containment pressure is reduced and stabilized. The fan cooling units would continue in operation alone during the long-term recirculation phase during which the containment pressure is continually reduced. In addition, effective recirculation is provided to all parts of the containment. Suction to the fan cooling units is taken from the upper portion of the containment and discharged from the fan coolers through a ring header to various compartments below the operating deck. 6.4.3.2 System Response The starting sequence of the five containment cooling fans and the related emergency power equipment is discussed in sections 7.2 and 8.2.3.4 and their analyzed performance is discussed in the various Chapter 14 safety analyses. 6.4.3.3 Single-Failure Analysis A failure analysis has been made on all active components of the system to show that the failure of any single active component will not prevent fulfilling the design function. This analysis is summarized in Table 6.4-1. The analysis of the loss-of-coolant accident presented in Section 14.3 is consistent with the single-failure analysis. 6.4.3.4 Reliance on Interconnected Systems The containment air recirculation cooling system is dependent on the operation of the electrical and service water systems. Cooling water to the coils is supplied from the service water system. Three nuclear service water pumps are provided, only two of which are required to operate during the postaccident period. 6.4.3.5 Shared Functions Evaluation Table 6.4-2 is an evaluation of the main components, which have been discussed previously and a brief description of how each component functions during normal operation and during the accident. Cha pter 6, Page 84 of 170 Revision 20 OAG10000215_0793

IP2 FSAR UPDATE 6.4.3.6 Reliability Evaluation of the Fan Cooler Motor The basic design of the motor and heat exchanger as described herein is such that the incident environment is prevented, in any major sense, from entering the motor winding or when entering in a very limited amount (equalizing motor interior pressure) the incoming atmosphere is directed to the heat exchanger coils where moisture is condensed out. If some quantity of moisture should pass through the coil, the changed motor interior environment would "cleanup" because the interior air continually recirculates through the heat exchanger. The increase temperature to 95°F will not impact the life expectancy of the motors. During the lifetime of the plant, these motors perform the normal heat removal service and as such are only loaded to approximately 120-150 hp. The bearings are designed to perform in the incident ambient temperature conditions. However, it will be noted that the interior bearing housing details are cooled by the heat exchanger. It is expected that bearing temperatures would be 125°C to 140°C under incident conditions. The insulation has high resistance to moisture and tests performed indicate the insulation system would survive the incident ambient moisture condition without failure. The heat exchanger function of preventing moisture from reaching the winding keeps the winding in much more favorable conditions. In addition, it will be noted that at the time of the postulated incident, the load on the fan motor would increase, internal motor temperature would increase, and would therefore tend to drive any moisture, if present, out of the winding. [Deleted] Following the incident rise in pressure, it is not expected that there will be significant mixing of the motor (closed system) environment and the containment ambient. The heat exchanger has been designed using a very conservative fouling factor. To prove the effectiveness of the heat exchanger in inhibiting large quantities of the steam-air mixture from impinging on the winding and bearings, a full-scale motor of the exact same type as described was subjected to prolonged exposure of accident conditions. The test exposed the motor to a steam-air mixture as well as boric acid and alkaline spray at 80 psig and saturated temperature conditions. Insulation resistance, winding and bearing temperature, relative humidity, voltage and current, as well as heat exchanger water temperature and flow were recorded periodically during the test. Following the test the motor was disassembled and inspected to ensure that the unit performed as designed. The posttesting inspection showed no degradation of the motor components (Details are reported in Reference 5). 6.4.4 Minimum Operating Conditions The Technical Specifications establish limiting conditions regarding the operability of the air recirculation units. Cha pter 6, Page 85 of 170 Revision 20 OAG10000215_0794

IP2 FSAR UPDATE 6.4.5 Inspections And Testing 6.4.5.1 Inspection Access is available for visual inspection of the containment fan-cooler and recirculation components including fans, cooling coils, butterfly valves, and ductwork. 6.4.5.2 Component Testing The butterfly valves on each air-handling unit can be operated periodically to ensure continued operability. The degree of leaktightness of the valves was established by test at the time of installation. 6.4.5.3 System Testing Each fan cooling unit was tested after installation for proper flow and distribution through the duct distribution system. Four of the fan cooling units are expected to be used during normal operation. Five will only be required for normal operation when the service water inlet temperature is 85°F or higher. The fan not in use can be started from the control room to verify readiness. The associated butterfly valves will be tested only when the fan is running. 6.4.5.4 Operational Sequence Testing The test described in Section 6.2.5 demonstrates proper transfer and sequencing of the fan motor supplies to the diesel generators in the event of loss of power. A test signal is used to demonstrate proper valve motion and fan starting. This test verifies proper functioning of the vane-switch flow indicators. REFERENCES FOR SECTION 6.4

1. Deleted

2. Deleted

3. Nuclear Safety Quarterly Report - August, September, October, 1969, Engineered Safety System Studies, BNWL-1266.

4. Deleted

5. C. V. Fields, Fan Cooler Motor Unit Development and Test, WCAP-9003 (Proprietary), Westinghouse Electric Corporation.

Cha pter 6, Page 86 of 170 Revision 20 OAG10000215_0795

IP2 FSAR UPDATE TABLE 6.4-1 Single Failure Analysis - Containment Air Recirculation Cooling System Component Malfunction Comments And Consequences A. Containment cooling fan Fails to start Five provided. Evaluation based on three fans in operation and one containment spray pump operating during the injection phase. B. Nuclear service water pumps Fails to start Three provided. Two required for operation. C. Automatically operated valves: (Open on automatic safeguards sequence)

1. Charcoal filter Fails to open None, charcoal filters are no compartment butterfly longer credited and have been valves removed.

2. Nuclear service water Fails to open Two provided. Operation of one discharge line isolation required.

valve TABLE 6.4-2 Shared Functions Evaluation Component Normal Normal Accident Accident Operation Operating Function Arrangement Function Arrangement Containment Circulate and Up to five fan Circulate and Five fan units in cooling fan cool units in service cool service units (5) containment containment atmosphere atmosphere Nuclear service Supply river Up to three Supply river Three pumps in water pump (3) cooling water to pumps in cooling water to service fan units service fan units 6.4 FIGURES Figure No. Title Figure 6.4-1 Deleted Figure 6.4-2 Deleted Cha pter 6, Page 87 of 170 Revision 20 OAG10000215_0796

IP2 FSAR UPDATE Figure 6.4-3 Containment Building Air Recirculation Fan Cooler Filter Unit - Plan and Section, Replaced with Plant Drawing 9321-4026 Figure 6.4-4 Deleted 6.5 ISOLATION VALVE SEAL-WATER SYSTEM 6.5.1 Design Bases The isolation valve seal-water system ensures the effectiveness of those containment isolation valves that are located in lines connected to the reactor coolant system or that could be exposed to the containment atmosphere during any condition, which requires containment isolation, by providing a water seal (and in a few cases a gas seal) at the valves. The system provides a simple and reliable means for injecting seal water between the seats and stem packing of the globe and double-disk types of isolation valves, and into the piping between closed-diaphragm type isolation valves. This system operates to limit the fission product release from the containment. Although the isolation valve seal-water system is designed to automatically initiate during any accident condition requiring containment isolation, the primary function of the system is to limit the fission product release associated with a large break LOCA. Although no credit is taken for the operation of this system in the calculation of offsite accident doses as discussed in Section 14.3.6, it does provide assurance that the containment leak rate is lower than that assumed in the accident analysis should an accident occur. Design provisions for inspection and testing of the isolation valve sealwater system are discussed in Section 6.5.5. See Section 5.2, containment isolation system, for containment isolation diagrams (Figures 5.2-1 through 5.2-29), the tabulation of isolation valve parameters (Table 5.2-1), and a description of the derivation of "phase A" and "phase B" containment isolation signals. Section 5.2.2 discusses the containment isolation valves that are sealed, postaccident, by air from the penetration and weld channel pressurization system. 6.5.2 System Design And Operation 6.5.2.1 System Description The isolation valve seal-water system flow diagram is shown in Plant Drawing 9321-2746 [Formerly UFSAR Figure 6.5-1]. System operation is initiated either manually or by a "phase A" containment isolation signal. When actuated, the isolation valve seal water system interposes water inside the penetrating line between two isolation points located outside the containment. The resulting water seal blocks the leak-age of the containment through valve seats and stem packing. The water is introduced at a pressure slightly higher (52 psig, minimum) than the containment design pressure of 47 psig. The high-pressure nitrogen supply used to maintain pressure in the seal-water tank does not require an external power source to maintain the required driving pressure. The possibility of leakage from the containment or reactor coolant system past the first isolation point is thus prevented by ensuring that if leakage does exist, it will be from the seal-water system into the containment. The following lines would be subject to pressures greater than the operating pressure of the seal water portion of the isolation valve seal-water system. These lines are supplied with 250 Cha pter 6, Page 88 of 170 Revision 20 OAG10000215_0797

IP2 FSAR UPDATE psig nitrogen for the high pressure portion of the system which exceeds worst case internal post-accident process pressure:

1. Residual heat removal loop inlet line.

2. Residual heat removal loop outlet line.

3. Bypass line from residual heat exchanger outlet to safety injection pumps suction.

4. Residual heat removal pumps mini-flow line.

5. Residual heat removal loop sample line.

6. Recirculation pump discharge sample line.

The isolation valves for those lines can be sealed by nitrogen gas from the high-pressure nitrogen supply of the isolation valve seal-water system. A self-contained pressure regulator operates to maintain the nitrogen injection pressure slightly higher than the maximum expected line pressure. The nitrogen gas injection is manually initiated. The system includes one seal-water tank capable of supplying the total requirements of the system. The tank is normally pressurized from the Nitrogen System through pressure control valves. As a backup, the tank may be pressurized from the system's own supply of high-pressure nitrogen cylinders through pressure control valves. Design pressure of the tank and injection piping [Note - The injection piping runs and nitrogen supply piping are fabricated using 3IB-in. -00 tubing, which is capable of 2500-psig service.] is 150 psig, and relief valves are provided to prevent overpressurization of the system if a pressure control valve fails, or if a seal-water injection line communicates with a high-pressure line due to a valve failure in the seal-water line. The design parameters of the seal-water tank are presented in Table 6.5-1. In lines approximately 3-in. and larger, double disk gate valves are generally used for isolation. A drawing of this valve is presented in Figure 6.5-2. Redundant isolation barriers are provided when the valve is closed. The upstream and downstream disks are forced against their respective seats by the closing action of the valve. Seal-water is injected through the valve bonnet and pressurizes the space between the two valve disks. The seal-water pressure in excess of the potential accident pressure eliminates any outleakage past the first isolation point. For smaller lines, isolation is generally provided by two globe valves in series with the seal-water injected into the pipe between the valves. The valves are oriented such that the seal water wets the stem packing. When the valves are closed for containment isolation, the first isolation point is the valve plug in the valve closest to containment and the water seal is applied between the valve plug and stem packing. In a number of the smaller lines, isolation is provided by two diaphragm (Saunders Patent) valves in series, with the seal water injected into the pipe between the valves. The maximum acceptable leakage across both the seat and stem packing of any gate or globe valve is nominally 10 cm3/hr-in. of nominal pipe diameter. Tests on these valves have indicated that much lower leakage rates can be expected. However, the design of the isolation valve seal-water system is based on the conservative assumption that all isolation valves are leaking at five times the acceptable value, or 50 cm3/hr-in. of nominal pipe diameter. In addition, a screening criterion of 25 cm 3/min for an individual isolation valve leakage has been established, beyond which point a determination will have to be made whether the valve is still functionally acceptable. Should one of the isolation valves close, but fail to seal, it is conservatively assumed that flow through the failed valve will be limited to approximately 100 times the maximum acceptable leakage valve, or 1000 cm3/hr-in. of nominal pipe diameter, by the resistance of seal-water injection path through the valve. Cha pter 6, Page 89 of 170 Revision 20 OAG10000215_0798

IP2 FSAR UPDATE If a containment isolation valve fails to close, a water seal at the failed valve is ensure by proper slope of the potential line, or a loop seal, or by additional valves on the side of the isolation valves away from the containment. Excessive seal-water flow to those motor operated isolation valves that could potentially fail to close in response to a containment isolation signal is limited by flow restrictive orifices installed in the seal-water injection lines. The seal-water tank is sized to provide at least 24-hr supply of seal-water with all of the isolation valves leaking at the design rate of 50 cm3/hr-in., plus the failure of the largest containment isolation valve to seat and leaking at the maximum rate of 1000 m3/hr-in. The seal-water volume required to satisfy these conditions is approximately 144 gal. The 176-gal seal-water tank is provided with low level and low-low level alarms to signal the need for makeup during normal operation and accident conditions, respectively. If all of the isolation valves seat properly, as expected, the tank volume is sufficient for more than 2.5 days of operation at design seal-water flow rates before makeup is required. Two separate sources of makeup water are provided to ensure that an adequate supply of seal-water is available for long-term operation. For an event resulting in a "phase A" containment isolation signal, but not a "phase B" containment isolation signal, the isolation valve seal-water system is automatically initiated. Flow to the four isolation valves associated with a "phase B" containment isolation signal only will be automatically isolated by solenoid operated valves, and remain isolated unless the containment isolation valves close. This design will prevent seal-water flow to the opened containment isolation valves. In the event that the solenoid operated valves fail to close, excessive flow would be limited to flow restrictive orifices installed in the seal-water injection lines. This design ensures sufficient time for operator action to provide make-up water if long-term system operation is required to limit fission product releases. If long-term isolation valve seal-water system operation is not required, the system may be isolated by operator action. There are two separate seal-water lines supplying the potentially radioactive and nonradioactive systems, respectively. This prevents the contamination of nonradioactive systems by way of isolation valve seal-water manifolds. 6.5.2.2 Seal-Water Actuation Criteria Containment isolation (Section 5.2) and seal-water injection are accomplished automatically on phase A isolation actuation for certain penetrating lines requiring early isolation, and manually for others, depending on the status of the system being isolated and the potential for leakage in each case. Generally, the following criteria determine whether the isolation and seal-water injection are automatic or manual. Automatic containment isolation and automatic seal-water injection are required for lines that could communicate with the containment atmosphere and be void of water following a loss-of-coolant accident. For example, these lines include:

1. Reactor coolant pump cooling water supply and return lines (phase B isolation).

2. Reactor coolant pump seal-water return line (phase B isolation).

3. Excess letdown heat exchanger cooling water supply and return lines (phase A isolation).

4. Chemical and volume control system letdown line (phase A isolation).

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5. Reactor coolant system sample lines and sample return line (phase A isolation).

6. Containment vent header (phase A isolation).

7. Reactor coolant drain tank gas analyzer line (phase A isolation).

S. Auxiliary steam supply and condensate return lines (Manual valves qualifying as automatic isolation valves per Section 5.2.2).

9. Service air and city water lines (Manual valves qualifying as automatic isolation valves per Section 5.2.2).

Automatic containment isolation and automatic seal-water injection are also provided for the following lines, which are not connected directly to the reactor coolant system, but terminate inside the containment at certain components. These components can be exposed to the reactor coolant or containment atmosphere as the result of leakage or failure of a related line or component. The isolated lines are not required for postaccident service. For example, these lines include:

1. Pressurizer relief tank gas analyzer line.

2. Pressurizer relief tank makeup line.

3. Safety injection system test line.

4. Reactor coolant drain tank pump discharge line.

5. Steam-generator blowdown/sample lines.

6. Accumulator sample line.

7. Containment sump pump discharge.

Remote manual containment isolation and remote manual seal-water injection are provided for lines that are normally filled with water and will remain filled following the loss-of-coolant accident and for lines that must remain in service for a time following the accident. The remote manual seal-water injection ensures a long-term seal. For example, these lines include:

1. Reactor coolant pump seal-water supply lines.

2. Chemical and volume control system charging line.

3. Safety injection headers.

4. Containment spray headers.

Manual containment isolation and remote manual nitrogen seal injection are provided for lines that are filled with water during the accident, but which are at a pressure higher than that provided by the isolation valve seal-water system. These lines must remain in service for a period of time following the accident or may be placed in service on an intermittent basis following the accident. For example, these lines include:

1. Residual heat removal loop inlet line.

2. Bypass line from residual heat exchanger outlet to safety injection pumps suction.

3. Residual heat removal loop sample line.

4. Recirculation pump discharge sample line.

Seal-water injection is not necessary to ensure the integrity of isolated lines in the following categories: Cha pter 6, Page 91 of 170 Revision 20 OAG10000215_0S00

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1. Lines that are connected to non-radioactive systems outside the containment and in which a pressure gradient exists, which opposes leakage from the containment. These include nitrogen supply lines to the pressurizer relief tank, accumulators, and reactor coolant drain tank, the instrument air header and the weld channel pressurization air lines.

2. Lines that do not communicate with the containment or reactor coolant system and are missile protected throughout their length inside containment. These lines are not postulated to be severed or otherwise opened to the containment atmosphere as a result of a loss-of-coolant accident. These include the steam and feedwater headers and the containment ventilation system cooling water supply and return lines.

3. Lines that are designed for postaccident service as part of the engineered safety features, such as the containment sump recirculation line. This line is connected to a closed system outside containment.

4. Special lines, such as the fuel transfer tube, containment purge ducts, and the containment pressure relief line, which are pressurized by the containment penetration and weld channel pressurization system (see Section 6.6). The zone between the two gaskets sealing the blind flange to the inner end of the fuel transfer tube is pressurized to prevent leakage from the containment in the event of an accident. The zone between the two butterfly valves in each containment purge duct is pressurized above incident pressure, while the valves are closed during power operation, as are the two spaces between the three butterfly valves in the containment pressure relief line.

6.5.2.3 Components All associated components, piping, and structures of the isolation valve seal-water system are designed to seismic Class I criteria. There are no components of this system located inside containment. The piping and valves for the system including the air-operated valves are designed in accordance with the USAS Code for Pressure Piping (Power Piping Systems), 831.1. 6.5.3 Design Evaluation The isolation valve seal-water system provides an extremely prompt and reliable method of limiting the fission product release from the containment isolation valves in the event of a loss-of-coolant accident. The employment of the system during a loss-of-coolant accident, while not considered for the analysis of the consequences of the accident as discussed in Section 14.3.6, provides an additional means of conservatism in ensuring that leakage is minimized. No detrimental effect on any other safeguards system will occur should the seal-water system fail to operate. Cha pter 6, Page 92 of 170 Revision 20 OAG10000215_0801

IP2 FSAR UPDATE 6.5.3.1 System Response Automatic containment isolation will be completed within approximately 10 sec following the generation of the phase A containment isolation signal. This is the estimated closing time of the non-essential containment isolation valves (Section 5.2). Closing times of greater than 10 seconds are permitted on a case by case basis if properly justified by a safety evaluation. Since the isolation valve seal-water system is also actuated by this signal, automatic seal-water injection will be in effect within this time period, which is less than the 1 min credited in Section 14.3.6.1. Subsequent generation of the phase B isolation signal on containment high-high pressure (spray actuation signal) will close the essential containment isolation valves with an estimated closing time of 10 sec. Closing times of greater than 10 seconds are permitted on a case by case basis if properly justified by a safety evaluation. Automatic seal-water injection flow will have been initiated in advance of this signal by the phase A signal. 6.5.3.2 Single-Failure Analysis A single-failure analysis is presented in Table 6.5-2. The analysis shows that the failure of any single active component will not prevent fulfilling the design function of the system. 6.5.3.3 Reliance on Interconnected Systems Normally the high-pressure nitrogen supply used to maintain pressure in the seal water tank is from the Nitrogen System. However, in the backup mode, when the tank is pressurized from the system's own supply of high-pressure nitrogen cylinders, the isolation valve seal-water system can operate and meet its design function without reliance on any other system. Electric power is not required for system operation, although instrument power is required to provide indication on the Waste Disposal Panel of seal-water tank pressure and level. 6.5.3.4 Shared-Function Evaluation Table 6.5-3 is an evaluation of the main components discussed previously and a brief description of how each component functions during normal operation and during an accident. 6.5.4 Minimum Operating Conditions The Technical Specifications establish limiting conditions regarding the operability of the system. 6.5.5 Inspections And Tests 6.5.5.1 Inspections The system components are all located outside the containment and can be visually inspected at any time. 6.5.5.2 Component Testing Each automatic isolation valve can be tested for operability at times when the penetrating line is not required for normal service. Lines supplying automatic seal-water injection can be similarly tested. Cha pter 6, Page 93 of 170 Revision 20 OAG10000215_0802

IP2 FSAR UPDATE 6.5.5.3 System Testing Containment isolation valves and the isolation valve seal-water system can be tested periodically to verify capability for reliable operation. The seal-water tank pressure and water level can be observed locally on the Waste Disposal Panel, and these parameters are also monitored continuously via local alarms on the Waste Disposal Panel and a category alarm in the control room. The system will not be in service during the containment leak rate test. 6.5.5.4 Operational Sequence Testing The capacity of the system to deliver water at the required rate was verified initially during the pre-operational test period of plant construction and startup. Prior to plant operation, a containment isolation test signal was used to ensure proper sequence of isolation valve closure and seal-water addition. TABLE 6.5-1 Isolation Valve Seal-Water Tank Number 1 Total volume, fe 23.6 Minimum volume, gal 144 Material ASTM A-24O Design pressure, psig 150 Design temperature, of 200 Operating pressure, psig 52-62 Operating temperature, of Ambient Code ASME UPV (Section VIII) TABLE 6.5-2 Single Failure Analysis - Isolation Valve Seal-Water System Component Malfunction Comments A. Automatically operated valves (open on phase A containment isolation signal)

1. Isolation valve for Fails to open Two provided. Operation of automatic injection one required.

headers B. Instrumentation Cha pter 6, Page 94 of 170 Revision 20 OAG10000215_0803

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1. Level transmitter Fails Local level indicator at tank also provided.

2. Pressure transmitter Fails Local pressure indicator at tank also provided TABLE 6.5-3 Shared Functions Evaluation Normal Normal Operating Operating Accident Accident Component Function Arrangement Function Arrangement Isolation valve None Lined up to Source of water Lined up to seal-water seal-water for sealing seal-water storage tank (1) injection piping isolation valves injection piping N2 supply None Lined up to Source of N2 to Lined up to bottles seal-water tank maintain seal seal-water and water tank injection piping tank and N2 N2 injection pressure and piping N2 to those valves sealed with isolation valve seal-water system 6.5 FIGURES Figure No. Title Figure 6.5-1 Isolation Valve Seal- Water System - Flow Diagram, Replaced with Plant Drawing 9321-2746 Figure 6.5-2 Double Disk Isolation Valve With Seal-Water Injection 6.6 CONTAINMENT PENETRATION AND WELD CHANNEL PRESSURIZATION SYSTEM 6.6.1 Design Bases The containment penetration and weld channel pressurization system provides a means for continuously pressurizing the positive pressure zones incorporated into the containment penetrations and the channels over the welds in the steel inner liner and certain containment isolation valves in the event of a loss-of-coolant accident. Although no credit is taken for system operation in the calculation of offsite accident doses as discussed in Section 14.3.6, it is designed as an engineered safety feature and does provide assurance that the containment leak-rate in the event of an accident is lower than that assumed in the accident analysis.

Chapter 6, Page 95 of 170 Revision 20 OAG10000215_0804

IP2 FSAR UPDATE The system is designed to provide a means for determining the leaktightness of the containment during power operation, thereby reducing the frequency for performing postoperational integrated leakage rate tests. 6.6.2 System Design And Operation The containment penetration and weld channel pressurization system is shown in Plant Drawing 9321-2726 [Formerly UFSAR Figure 6.6-1]. A regulated supply of clean and dry compressed air from either of the plant's 100-psig compressed air systems located outside the containment is supplied to all containment penetrations and inner liner weld channels. The system maintains a pressure in excess of containment design pressure continuously during all reactor operations, thereby ensuring that there will be no outleakage of the containment atmosphere through the penetrations and liner welds during an accident. Typical piping and electrical penetrations are described in Sections 5.1 and 5.2. The primary source of air for this system is the instrument air system (Section 9.6). Two instrument and control air compressors are used, although only one is required to maintain pressurization at the maximum allowable leakage rate of the pressurization system. The station air compressor acts as a backup to the instrument and control air compressors (Section 9.6) for added reliability. A standby source of gas pressure for the system is provided by the bank of nitrogen cylinders. The associated nitrogen backup system will actuate a low weld channel pressure of approximately 49 psig and deliver nitrogen to the main weld channel pressure regulator. This regulator controls downstream weld channel pressure to containment at approximately 52 psig. Thus, in the event of failure of the normal and backup air supply systems during periods when the system is in operation, the penetration and weld channel pressure requirements will be automatically maintained by the nitrogen supply. This ensures reliable pressurization under both normal and accident conditions. Containment penetrations and liner weld channels are grouped into four independent zones to simplify the process of locating leaks during operation. Each such zone is served by its own air receiver. In the event that all normal and backup air supplies are lost, each of the four pressurization system zones continues to be supplied with air from its respective air receiver. Each of the air receivers, (see Table 6.6-1), is sized to supply air to its pressurized zone for a period of at least 4 hr, based on a leakage rate of 0.2-percent of the containment free volume per day (0.1-percent leakage into the containment and 0.1-percent leakage to the environment). If the receivers become exhausted before normal and backup air supplies can be restored, nitrogen from the bank of pressurized cylinders can be supplied to the affected zones. The nitrogen bank is sized to provide a 24-hr supply of gas to the system, again based on a total leakage rate from the pressurization system of 0.2-percent of the containment free volume in 24 hr. There are three nitrogen cylinders in the bank, each approximately 24-in. 00 by 20-ft 6%-in long, providing a total volume of 153 cu-ft (51 cu-ftlcylinder). The nitrogen supply will also automatically assume the pressurization gas load in the event an air receiver fails. A pressure relief valve set at 150 psig (sized for 167 scfm at 10-percent accumulation) protects the system from failure of the pressure-reducing valve in the line to each zone from the bank of nitrogen cylinders. Each zone of piping is also protected by a rupture disk, designed to open at 175 psig. In addition, the electric penetration assemblies (Zone 1) are protected by a pressure relief valve set at 70 psig. Pressure control valves, isolation valves, and check valves are Cha pter 6, Page 96 of 170 Revision 20 OAG10000215_0805

IP2 FSAR UPDATE located outside of the containment for ease of inspection and maintenance. The failure of any of these components does not lead to a loss of pressure in the system since backup systems automatically augment the normal air supply. The line to each of the four pressurized zones is equipped with a critical pressure drop orifice (installed in the pressure control valve body) to ensure that air consumption will be within the capacity of the system. High air consumption in one zone cannot affect the operation of the other zones under any circumstances. Means for ensuring that all the weld channels and penetrations are pressurized is provided by flow-through test lines connected to the pressurized weld channel zones and penetrations at points as far away from the supply points as possible. The pressurization of the zone can be verified by closing off the air supply line and opening the flow-through test line valve to observe the escape of the pressurizing medium. Certain portions of the Weld Channel Pressurization System may be disconnected if that portion has become inoperable and repairs to that portion of the system have been determined not to be practicable. Currently, sections W-10, W-11, 0-2, 8-2, 8-5 and 8-6 are disconnected. The method of disconnection is selected so as not to interfere with the ability to pressurize those portions of weld channel to containment atmospheric conditions during an integrated leak rate test (lLRT) in accordance with 10 CFR 50 Appendix J. 6.6.2.1 Pressure Indication The following instrumentation is provided as described below to ensure that the station operators are aware at all times that all penetrations and liner weld seam channels are pressurized. The following pressurized zones are equipped with local pressure gauges, mounted outside the containment for ready accessibility and available for regular reading.

1. Each piping penetration.

2. Each electrical penetration.

3. The spaces between the two isolation (butterfly) valves in the purge supply and exhaust ducts.

4. The two spaces between the three isolation (butterfly) valves in the containment pressure relief line.

5. The double-gasketed space on the outside hatch of each of the two personnel air locks.

The pressurized zones located entirely inside the containment and those zones located in inaccessible areas are equipped to actuate pressure switches to provide remote low-pressure alarms in the central control room. Examples of the zones so equipped are as follows:

1. Each liner seam weld channel, except for the disconnected zones listed in Section 6.6.2.

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2. The double-gasketed space on each inside hatch of the personnel airlocks.

3. The double-gasketed space on the equipment door flange.

4. The pressurized zones in the spent fuel transfer tube.

5. Shroud rings over penetration-to-containment liner weld piping and electrical penetrations.

The control room low pressure alarm switches and the nitrogen backup actuation switches are set above incident pressure and below the pressure setting of the main weld channel pressure regulators. Should pressure in any of these zones fall below the alarm pressure switch setpoint, a light and an alarm in the control room will be activated. Each penetration and each section of liner weld joint channel so alarmed will be represented by a separate light and identified. 6.6.2.2 Flow Indication The flow to each zone is measured by two meters mounted in series. In addition to indication, low and high flow alarms are provided in the control room. 6.6.2.3 Personnel Air Lock Interlock Continuous pressurization of air lock door double-gasketed barriers and the protection of the pressurization header against air loss are ensured by a set of interlocks. One interlock on each airlock door prevents the opening of the door until the pressurization line is isolated and pressure in the double-gasketed closure is relieved to atmosphere. This prevents excessive leakage from the pressurization system. The pressurization line to this zone is also equipped with a restricting orifice to ensure that air consumption, even upon failure of the interlock, will be within the capacity of the pressurization system, and will not result in a loss of pressure in other zones connected to the same pressurization header. Another set of interlocks prevents opening of one air lock door until the double-gasketed zone on the other door is repressurized. 6.6.2.4 Containment Purge Line Interlock The containment ventilation purge penetration butterfly valves inside containment are interlocked to prevent their opening until the pressurization line to each purge duct pressurization zone has been isolated and the space between been depressurized. The isolation of the pressurization line to each purge duct-pressurized zone is accomplished from the fan room. Alarm lights, prominently displayed on a panel indicating the isolation status of the containment, remain lit identifying an open purge duct isolation valve or a low pressurization zone pressure. Restricting orifices are installed in each pressurization line to the ventilation purge ducts to ensure that air consumption, even on the failure of an interlock, will not result in a loss of pressure to the other zones connected to the same pressurization header. The containment pressure relief line isolation valve inside containment (PCV-1190), and the pressurized space formed between it and the next butterfly valve in series, are provided with an interlock to prevent the opening of PCV-1190 until the adjacent intervalve space has been depressurized. By procedure the outside containment pressure relief line isolation valves PCV-1191 and PCV-1192 are opened from the central control room after isolation valve PCV-1190 is verified open. A time delay allows the pressurized space between the two outside isolation valves to vent air through the associated solenoid valve to atmosphere before these Cha pter 6, Page 98 of 170 Revision 20 OAG10000215_0807

IP2 FSAR UPDATE valves will open. The pressurization lines to these spaces are also equipped with flow restricting orifices; alarm lights in the control room identify open valves or low intervalve space pressure. 6.6.2.5 Containment Inleakage With a continuous inleakage to the containment from the penetration and liner weld joint channel pressurization system of 0.1-percent of the containment volume per day, the calculated time for the containment pressure to rise by 1 psi is approximately 14 days and therefore is not considered to be an operating or safety problem. From the standpoint of allowable pressure, a much greater inleakage would be permitted. With the ability to limit the activity of the air in the containment during normal operation with the use of the two containment auxiliary charcoal filter units, each complete with roughing filter, HEPA filters, and charcoal filters (Section 5.3), containment overpressure can be relieved as required through the pressure relief duct and exhaust fan, passing up the discharge duct along with the exhaust air from the primary auxiliary building. 6.6.2.6 Components All associated components, piping, and structures of the containment penetration and weld channel pressurization system are designed to seismic Class I criteria. The piping and valves for the system are designed in accordance with the USAS Code for Pressure Piping (Power Piping Systems), B31.1. For a description of the instrument and control air compressors and the plant air compressors, refer to the discussion on the service air system, Section 9.6. The three nitrogen cylinders used are designed in accordance with Section VIII (Unfired Pressure Vessels) of the ASME Boiler and Pressure Vessel Code for 2200-psig maximum pressure and contain a total of 22,000 scf of nitrogen. 6.6.3 Design Evaluation The employment of this system following a loss-of-coolant accident, while not considered in the analysis of the consequences of the accident as discussed in Section 14.3.6, provides an additional means for ensuring that leakage is minimized if not altogether eliminated. No detrimental effect on any other safety features system will be felt should the pressurization system fail to operate. 6.6.3.1 System Response Since the containment penetration and weld channel pressurization system is continuously pressurized above the containment design pressure during all reactor operations, there is no response time required for the system to operate. 6.6.3.2 Single Failure Analysis A single failure analysis is presented in Table 6.6-2. The analysis shows that the failure of any single active component will not prevent fulfilling the design function of the system. Cha pter 6, Page 99 of 170 Revision 20 OAG10000215_0808

IP2 FSAR UPDATE 6.6.3.3 Reliance on Interconnected Systems The containment penetration and weld channel pressurization system can operate and meet its design function without reliance on any other system, except as limited by air compressor availability following the depletion of all reserves in the system's air receivers and backup nitrogen cylinders. Electric power is not necessary for the operation of the system, although instrument power is required in order to provide indications in the control room of system operation. 6.6.3.4 Shared Functions Evaluation Table 6.6-3 is an evaluation of the main components discussed previously and a brief description of how each component functions during normal operation and during an accident. 6.6.4 Minimum Operating Conditions The Technical Specifications establish limiting conditions regarding the operability of the system. 6.6.5 Inspections And Tests 6.6.5.1 Inspections The system components located outside the containment can be visually inspected at any time. Components inside the containment can be inspected during shutdown. All pressurized zones have provisions for either local pressure indication outside the containment or remote low-pressure alarms in the control room, except for low pressure alarm lights associated with the disconnected weld channel zones listed in Section 6.6.2. 6.6.5.2 Testing Since the system IS In operation continuously during all reactor operations to maintain the penetrations and liner weld channels pressurized above containment design pressure, no special testing of system operation or components is necessary. Should one zone indicate a leak during operation, the specific penetration or weld channel containing the leak can be identified by isolating the individual air supply line to each component in the zone and injecting leak test gas through a capped tube connection installed in each line. Total leakage from penetrations and weld channels is measured by summing the recorded flows in each of the four pressurization zones. A leak would be expected to build up slowly and would therefore be noted before design leakage limits are exceeded. Thus, remedial action can be taken before the limit is reached. In order to provide facility for containment testing in accordance with Technical Specification 4.4 and 10 CFR 50 Appendix J, test connections are provided in each of the zones. Flow Instrumentation is installed in the piping to the personnel air locks during testing to provide measurement of the airlock leakage rate independent of the other components served by the same zone. Chapter 6, Page 100 of 170 Revision 20 OAG10000215_0809

IP2 FSAR UPDATE The makeup air flow to the penetrations and liner weld joint channels during normal operation is recognized to be only an indication of the potential leakage from the containment. However, it does indicate the leakage from the pressurization system, and the degree of accuracy will be increased when correlated with the results of the full-scale containment leak rate tests. The criteria for the selection of operating limits for air consumption of the pressurization system are based upon the design integrated containment leak rate and upon the maintenance of suitable reserve air supplies in the static reserves consisting of the air receivers and nitrogen cylinders. A summary of these operating limits is as follows:

1. A baseline air consumption rate was established for each of the four pressurization headers at the time of successful completion of the pre-operational integrated containment leakage rate tests. Unexplained increases from this consumption rate shall be considered as reason for concern and normal practice will require routine investigation and location of the point of leakage.

2. The upper limit for long-term uncorrected air consumption for the pressurization system shall be 0.2-percent of the containment volume per day (sum of four zones) at the system operating pressure, contingent on the following:

a. Pressure in all pressurization zones is maintained above incident pressure.

b. Air supply is maintained from the compressed air systems with compressors running.

c. The full complement of standby nitrogen cylinders (three) is charged. This is consistent with maintenance of a 24-hr supply.

A variable area flow sensing device is located in each of the headers supplying makeup air to the four pressurization zones. The flow sensing device for each zone has two flow transmitters (high and low). Signal output from each of the two flow transmitters is applied to an integrator which has an output to a flow indicator for each zone located in the control room. Output from each of the four integrators is also applied to a single summing amplifier that drives a single total-flow recorder which is also located in the control room. Two high-flow alarms (one short term and one long term) are also derived in the recording channel to alert the operator in the control room. TABLE 6.6-1 Containment Penetration And Weld Channel Pressurization Air Receivers Number 4 Volume (each), ft 3 360 Material ASTM A-285-C Design pressure, psig 140 Design temperature, of 200 Operating pressure, psig 100 Operating temperature, of 100 Code ASM E UPV (Section VIII) Chapter 6, Page 101 of 170 Revision 20 OAG10000215_0810

IP2 FSAR UPDATE TABLE 6.6-2 Single Failure Analysis Containment Penetration And Weld Channel Pressurization System Component Malfunction Comments Instrument and control air Fails to maintain pressure One of two instrument and compressor control air compressors required to operate. Pressure-reducing valve for Fails to maintain pressure On valve failure, flow is each zone limited to acceptable value (75 scfm) by the critical pressure drop orifice. Under low-flow conditions, overpressurization of system downstream of valve is prevented by a rupture disk. TABLE 6.6-3 Shared Functions Evaluation Normal Normal Operating Operating Accident Accident Component Function Arrangement Function Arrangement Instrument and Supply air to 2 air Supply air to 1 air control air plant's compressors in penetrations compressor1 in compressors instruments operation and weld operation (2) and controls channels and to penetrations and weld channels Station air Supply air to 1 air Supply air to 1 air compressors station air compressor in penetrations compressor1 in (1 ) headers operation and weld operation channels N2 cylinders (3) Backup source Lined up to Backup source Lined up to of N2 to penetration and of N2 to penetration and maintain weld channel maintain weld channel penetration and pressurization penetration and pressurization channel system weld channel system Chapter 6, Page 102 of 170 Revision 20 OAG10000215_0811

IP2 FSAR UPDATE pressure pressure Air receivers (1) Primary source Lined up to Primary source Lined up to and dryers (3) of air for penetrations of air for penetration and penetrations and weld penetrations weld channel and weld channel and weld pressurization channels pressurization channels system system Notes:

1. Assuming offsite power available.

6.6 FIGURES Figure No. Title Figure 6.6-1 Weld Channel and Penetration Pressurization System - Flow Diagram, Replaced with Plant Drawing 9321-2726 6.7 LEAKAGE DETECTION AND PROVISIONS FOR THE PRIMARY AND AUXILIARY COOLANT LOOPS 6.7.1 Leakage Detection Systems The leakage detection systems reveal the presence of significant leakage from the primary and auxiliary coolant loops. 6.7.1.1 Design Bases 6.7.1.1.1 Monitoring Reactor Coolant Leakage Criterion: Means shall be provided to detect significant uncontrolled leakage from the reactor coolant pressure boundary. (GDC 16) Positive indications in the control room of the leakage of coolant from the reactor coolant system to the containment are provided by equipment that permits continuous monitoring of containment air activity and humidity and of runoff from the condensate collecting pans under the cooling coils of the containment air recirculation units. This equipment provides an indication of normal background, which is indicative of a basic level of leakage from primary systems and components. Any increase in the observed parameters is an indication of change within the containment, and the equipment provided is capable of monitoring this change. The basic design criterion is the detection of deviations from normal containment environmental conditions, including air particulate activity, radiogas activity, humidity, condensate runoff, and in addition, in the case of gross leakage, the liquid inventory in the process systems and containment sump. 6.7.1.1.2 Monitoring Radioactivity Releases Criterion: Means shall be provided for monitoring the containment atmosphere and the facility effluent discharge paths for radioactivity released from normal operations, Chapter 6, Page 103 of 170 Revision 20 OAG10000215_0812

IP2 FSAR UPDATE from anticipated transients, and from accident conditions. An environmental monitoring program shall be maintained to confirm that radioactivity releases to the environs of the plant have not been excessive. (GDC 17) The containment atmosphere, the ventilation exhaust from the residual heat removal pump compartments, the containment fan cooler service water discharge, the component cooling loop liquid, the liquid phase of the secondary side of the steam generator, and the condenser air ejector exhaust are monitored for radioactivity concentration during normal operation, anticipated transients, and accident conditions. 6.7.1.1.3 Principles of Design The principles for the design of the leakage detection systems can be summarized as follows:

1. Increased leakage could occur as the result of a failure of pump seals, valve packing glands, flange gaskets, or instrument connections. The maximum leakage rate calculated for these types of failures is 50 gpm, which would be the anticipated flow rate of water through the pump seal if the entire seal were wiped out and the area between the shaft and housing were completely open.

2. The leakage detection systems should not produce spurious annunciation from normal expected leakage rates, but should reliably annunciate increasing leakage.

3. Increasing leakage rate is to be annunciated in the control room. Operator action is required to isolate the leak in the offending system.

6.7.1.2 Systems Design and Operation For Class 1 systems located outside the containment, leakage is determined by one or more of the following methods:

1. For systems containing radioactive fluids, leakage to the atmosphere would result in an increase in local atmospheric activity levels and would be detected by either the plant vent monitors or by one of the area radiation monitors. Similarly, leakage to other systems that do not normally contain radioactive fluids would result in an increase in the activity level in that system.

2. For closed systems such as the component cooling system, leakage would result in a reduction in fluid inventory.

3. All leakage would collect in specific areas of the building for subsequent handling by the building drainage systems, e.g., leakage in the vicinity of the residual heat removal pumps would collect in the sumps provided, and would result in the operation, or increased operation, of the associated sump pumps and increased inventory in the liquid waste processing system.

Details of how these methods are used to detect leakage from Class 1 systems other than the reactor coolant system are given in the following sections and summarized in Table 6.7-1. Chapter 6, Page 104 of 170 Revision 20 OAG10000215_0813

IP2 FSAR UPDATE The Class 1 fluid systems for which no special leak detection outside containment is provided include the following:

1. Residual heat removal.

2. Component cooling.

3. Service water.

4. Auxiliary feedwater.

5. Waste disposal.

Various methods are used to detect leakage from either the primary loop or the auxiliary loops. Although described to some extent under each system description, all methods are included here for completeness. 6.7.1.2.1 Reactor Coolant System In considering potential leakage from the reactor coolant system containing primary coolant at high pressure, four categories should be considered:

1. Leakage to the reactor coolant drain tank.

2. Leakage to the pressurizer relief tank.

3. Leakage to the containment environment.

4. Leakage to the interconnecting systems.

For clarity, each of these paths are discussed in turn. 6.7.1.2.1.1 Paths Directed to the Reactor Coolant Drain Tank The routes directed to the reactor coolant drain tank may be summarized as follow:

1. Reactor coolant system loop drains.

2. Accumulator drains.

3. Auxiliary system equipment drains.

4. Excess letdown.

5. Valve leakoffs.

6. Reactor coolant pump seal leakage.

7. Reactor flange leakoff.

Of these paths, (1) through (4) do not present a leakage load on the reactor coolant drain tank during normal operation; leakage from the high-pressure systems is not expected because of the use of double isolation valves. Leakage paths (5) through (7), above, are evaluated as follows: Valve Leakoffs Source - ThereCir~J$1 valves in the containment provided with leakoff connections. Of these valves, only (Dgl~H~q] four valves in the safety injection system will normally have their valve stem packing subjected to pressure. These are: Chapter 6, Page 105 of 170 Revision 20 OAG1000021S_0814

IP2 FSAR UPDATE 894A,8,C,D Accumulator isolation valves that are normally open are provided with backseats. Leakage would only be of borated radioactive water. Estimated Leakage - Total leakage of reactor coolant fluid during normal power operation is a conservatively estimated to be cm 3 /hr per the following: For valves 894A, 8, C, and D, leakages are assumed to be 2 cm 3/hr per valve, a total leakage of 8 cm 3/hr is assumed. Indication to Operator - The operator is alerted to abnormal conditions by an increase of the drain tank water temperature and eventually the change in tank level. Drain tank temperature, pressure, and level are continuously indicated on the "waste disposal/boron recycle" panel in the auxiliary building; high pressure, high temperature, high level, and low level are annunciated on this panel. Any alarm on this panel causes the annunciation of a single window on the main control board in the central control room. Reactor Coolant Pump Seals Source - Charging flow is directed to the reactor coolant pumps via a seal-water injection filter and enters each pump at a point between the labyrinth seals and the No. 1 face seal. Here the flow splits and a portion (normally about 5 gpm) enters the reactor coolant system via the labyrinth seals and thermal barrier cooler cavity. The remainder of the flow (normally about 3 gpm) flows up the pump shaft (cooling the lower bearing) and leaves the pump via the No.1 seal where its pressure is reduced to about 25 to 30 psig and its temperature is increased from 130°F to about 136°F. The labyrinth flows (20 gpm total for four reactor coolant pumps) are removed from the system as a portion of the letdown flow. The No.1 seal discharges (12 gpm total for four reactor coolant pumps) flow to a common manifold and then via a filter (seal-water filter) through the seal-water heat exchanger (where the temperature is reduced to about 130°F) to the volume control tank. The leakoff system between the No. 2 and No. 3 seals is considered to be part of the reactor coolant system. The leakoff system collects leakage passed by the No.2 seal, and provides a constant backpressure on the No.2 seal and constant pressure on the No.3 seal. A standpipe is provided to give a constant backpressure during normal operation. The first outlet from the standpipe is orificed to permit normal No. 2 seal leakage to flow to the reactor coolant drain tank; excessive No.2 seal leakage will result in a rise in the standpipe level and eventual overflow to the reactor coolant drain tank via a second overflow connection. Leakage - The normal No.2 seal leakage is anticipated to be approximately 3 gph per pump. This is the value specified in the reactor coolant pump equipment specification. Indication to Operator - Level instrumentation on the standpipes is provided to alert the operator to abnormal conditions. The standpipe consists of a pipe with an orificed overflow above the midpoint, a normally closed drain (for service) at the bottom, and a free-flowing overflow at the top. Normal No.2 seal leakage will flow freely out the orificed overflow. Excessive leakage will "back up" in the standpipe until it overflows at the top. A level switch in the upper standpipe actuates an annunciator indicating excessive flow. A level switch in the lower standpipe causes the annunciation of the opposite condition, which could result in undesirable dry operation of the No.3 seal. Chapter 6, Page 106 of 170 Revision 20 OAG10000215_0815

IP2 FSAR UPDATE Reactor Vessel Flange Leakoff Source - The reactor vessel flange and head are sealed by two metallic O-rings. To facilitate leakage detection, a leakoff connection is placed between the two O-rings and a leakoff connection is placed beyond the outer O-ring. Piping and associated valving is provided to direct any leakage to the reactor coolant drain tank. Leakage - During normal operation, it is anticipated that the leakage will be negligible since it is specified in the reactor vessel equipment specification that there is to be zero leakage past the outer O-ring under normal operating and transient conditions. Indication to Operator - A temperature detector will indicate leakage by a high temperature alarm. The operator is further alerted by the associated increase in drain tank water temperature and eventually the change in tank level. 6.7.1.2.1.2 Paths Directed to the Pressurizer Relief Tank These leakage routes are evaluated below. Source - The pressurizer relief tank condenses and cools the discharge from the pressurizer safety and relief valves. Discharge from small relief valves located inside the containment is also piped to the relief tank. During normal operation, leakage could possibly occur from either the pressurizer safety valves, pressurizer relief valves, or the chemical and volume control system letdown station relief valve. Leakage - During normal operation, the leakage to the pressurizer relief tank is expected to be negligible since the valves are designed for essentially zero leakage at the normal system operating pressure as specified in the respective valve equipment specifications. Indication to Operator - For these valves, temperature detectors are provided as an indication of possible leakage. In addition, each pressurizer safety valve is provided with an acoustic monitor in the discharge piping to alert the operator to possible leakage. The rate of increase of the water temperature in the pressurizer relief tank and the level change will indicate to the operator the magnitude of the leakage. In the event of excessive leakage into an interconnecting system causing lifting of the local relief valves, the operator would again be alerted to the situation by a rising tank water temperature (refer to Section 6.7.1.2.1.4). The acoustic monitors provide a gross indication of safety valve leakage via an alarm in the central control room. 6.7.1.2.1.3 Releases to the Containment Environment Leakage to the containment environment is discussed as follows. Source - The main contributors of leakage to the containment environment may be listed as follows:

1. Valve stem leakages As previously discussed, the modulating valves within the containment are provided with leakoff connections, which in turn are either piped to the reactor coolant drain tank or are capped. Of the remaining valves that serve lines and Chapter 6, Page 107 of 170 Revision 20 OAG10000215_0816

IP2 FSAR UPDATE components containing reactor coolant, only two are not normally fully open or fully closed; i.e., the continuous spray bypass needle valves around the main spray valves. The remaining valves are of the backseated type, which prevent the valve stem packings from being subjected to high pressures when in the open position.

2. Reactor coolant pump No.3 seal leakage A small continuous leakage is anticipated past the No. 3 seal to the containment environment; this fluid will be seal injection water. The No.3 seal leakoff is diverted to the local open drains and is thus released to the containment environment.

3. Weld flanges The welded joints throughout the system are subjected to extensive nondestructive testing; leakage through metal surfaces and welded joints is very unlikely.

4. Flange joints There are a number of flanged joints in the system, all of which are subjected to leak testing before power operation. Experience has shown that hydrostatic testing is successful in locating leaks in a pressure-containing system.

Methods of leak location that can be used during plant shutdown include visual observation for escaping steam or water or for the presence of boric acid crystals near the leak. The boric acid crystals would be present near the leak as a result of the evaporation process of the leaking fluid. Leakages - The main contributors to leakage to the containment environment are considered to be items 1 and 2 above; experience with operating reactors has shown that following the normal preoperational testing, leakage from these sources are negligible.

1. Valves stems Normally open valves have backseats that limit leakage to less than 1 cm3/hr-in.

of stem diameter assuming no credit for packing in the valve. Normally closed globe valves are installed with recirculation flow under the seat to prevent stem leakage from the more radioactive fluid side of the seat. On the basis of these pessimistic assumptions, the leakage from valves is estimated to be approximately 50 cm3/hr.

2. Reactor coolant Pump No.3 Seal Leakage The fluid will be seal injection water and is anticipated to be approximately 100 cm 3/hr per pump. This is the value specified in the reactor coolant pump equipment specification.

Conclusion - On the basis of the above, the analysis of the situation indicates a total leak rate to the containment environment of about 450 cm3/hr. For design purposes, 50 Ib/day (i.e., 1000 cm 3/hr) is assumed. Allowable reactor coolant leakage rate and leakage rate to the containment free volume are specified in the Technical Specifications. Chapter 6, Page 108 of 170 Revision 20 OAG10000215_0817

IP2 FSAR UPDATE 6.7.1.2.1.4 Leakage to Interconnecting Systems Leakage paths to interconnecting systems are evaluated below. System Discussion Chemical and This is a normally operating interconnecting system with volume control redundancy for isolating purposes if required. system Sampling system In the event of sample valves failing to close or seat, adequate redundancy is provided by containment isolation valves; the piping between the sets of valves is designed for reactor coolant system pressure. Residual heat Two isolation valves are provided; in the unlikely event of leakage removal system past the two valves, interconnecting piping is provided to enable hot leg pressure relief via the residual heat removal system loop relief connection valve to the pressurizer relief tank. Residual heat In the unlikely event of leakage past the accumulator check removal system valves, residual heat removal system loop check valves and the cold leg motorized isolation valves, pressure relief will take place via the residual heat removal system loop relief valves to the pressurizer relief tank. Safety injection In the event of leakage past the check valves and motorized gate system high- valve in anyone of the four cold leg injection lines or check valves head pump and motorized gate valve in either of the two hot-leg injection injection lines lines, pressure relief will take place to the pressurizer relief tank via the relief valve in the safety injection system test line. Safety injection Provisions have been made to check the leak-tightness of the system accumulator check valves. Leakage past these valves is accumulator discussed in Section 6.2. connections Leakage of primary fluid to the secondary system via the steam-generator primary/secondary boundary would result in an increase of activity level in the secondary system and would be detected by the condenser air ejector gas monitor or by the steam-generator liquid sample monitor. (Refer to Section 11.2.) During normal operation and anticipated reactor transients, the following methods are employed to detect leakage from the reactor coolant system. 6.7.1.2.2 Containment Air Particulate Monitor This channel takes continuous air samples from the containment atmosphere and measures the air particulate beta radioactivity. The samples, drawn outside the containment, are in a closed, sealed system and are monitored by a scintillation detector assembly. This assembly collects particulate matter greater than 1 micron in size on its moving filter paper surface, which is Chapter 6, Page 109 of 170 Revision 20 OAG10000215_0818

IP2 FSAR UPDATE viewed by a scintillation photomultiplier combination. After passing through the gas monitor, the samples are returned to the containment. The filter paper has a 25-day minimum supply at normal speed. The filter paper mechanism, an electromagnetic assembly, which controls the filter paper movement, is provided as an integral part of the detector unit. The detector assembly is in a completely closed housing. The detector output is amplified by a preamplifier, processed and transmitted to the radiation monitoring system console, safety related display console and a recorder in the control room. Lead shielding is provided to reduce interference with the detector's sensitivity caused by background radiation. The activity is indicated on digital displays and recorded by a multipoint recorder. High-activity alarm indications are displayed on the control board annunciator and the safety related display console. Local alarms provide operational status of supporting equipment such as pumps, motors, and flow and pressure controllers. The containment air particulate monitor is sensitive to low rates. The rates of reactor coolant leakage to which the instrument is sensitive are 0.1 gpm to greater than 10 gpm, assuming corrosion product activity and no fuel cladding leakage. Under these conditions, an increase in reactor coolant system leakage of 1 gpm is detectable within 1 hour after it occurs. The sensitivity of the air particulate monitors to an increase in reactor coolant leak rate is dependent upon the magnitude of the normal baseline leakage into the containment. The sensitivity is greatest where baseline leakage is low as has been demonstrated by the experience of Indian Point Unit 1 (Appendix 68), Yankee Rowe, and Dresden Unit 1. Assuming a low background of containment air particulate radioactivity, if we assume a reactor coolant corrosion product radioactivity (Fe, Mn, Co, Cr) of approximately 0.4 IlCilcm3 (a value consistent with little or no fuel cladding leakage), and complete dispersion of the leaking radioactive solids into the containment air, the air particulate monitors would be capable of detecting an increase in coolant leakage rate as small as approximately 0.1 gpm (400 cm 3/min) within 20 min after it occurs. If only 10-percent of the particulate activity were a assumed to be dispersed in the air, leakage rate increases of about 1.0 gpm (4000 cm 3/min) would be detectable within the same time period. For cases where baseline reactor coolant leakage falls within the detectable limits of the air particulate monitor, the instruments can be adjusted to alarm on leakage increases of from 2 to 5 times the baseline volume. The containment air particulate monitor together with the other radiation monitors mentioned in this section are further described in Section 11.2. 6.7.1.2.3 Containment Radioactive Gas Monitor This channel measures the gaseous gamma radioactivity in the containment by taking the continuous air samples from the containment atmosphere, after they pass through the air particulate monitor, and drawing the samples through a closed, sealed system to the gas monitor assembly. The samples are constantly drawn through the fixed, shielded volumes and are viewed by a scintillation detector. The samples are then returned to the containment. Chapter 6, Page 110 of 170 Revision 20 OAG10000215_0819

IP2 FSAR UPDATE The detector is in a completely enclosed housing containing a gamma-sensitive scintillation detector mounted in a constant gas volume container. Lead shielding is provided to reduce interference with the detector's sensitivity caused by background radiation. The detector output is amplified by a preamplifier, processed and transmitted to the radiation monitoring system console, the safety related display console and a recorder in the control room and indicated on digital displays. High-activity alarm indications are displayed on the control board annunciator and the safety related display console. Local alarms annunciate the supporting equipment's operational status. The containment radioactive gas monitor is inherently less sensitive (threshold at 10-6 IlCilcm3) than the containment air particulate monitor and would function in the event that significant reactor coolant gaseous activity exists from fuel cladding defects. The measuring range is 10-6 to 10-3 IlCilcm3. The containment air particulate and radioactive gas monitors have assemblies that are common to both channels. They are described as follows:

1. Each flow assembly includes a pump unit and selector valves that provide a representative sample (or a "clean" sample) to the detector.

2. The pump unit consists of:

a. A pump to obtain the air sample.

b. A flowmeter to indicate the flow rate.

c. A flow control valve to provide flow adjustment.

d. A flow alarm assembly to provide a low flow alarm signal.

3. Selector valves are used to direct the desired sample to the detector for monitoring and to vent flow when the channel is in maintenance or "purging" condition.

4. A pressure sensor is used to protect the system from high pressure. This unit automatically closes an inlet and outlet valve upon a high-pressure condition.

5. Purging is accomplished with a valve control arrangement whereby the normal sample flow is blocked and the detector purged with a "clean" sample.

6. The safety related display console in the control room permits remote operation of the local radiation monitor skid assembly. By operating a pushbutton on the console to start the sample pump, the containment sample can be monitored.

7. A sample flowmeter is calibrated linearly (from minute).

                                                                    ° to 56.6 standard liters per In addition to a common CCR High Rad/Trouble Annunciator, the following alarm lights are provided locally:

1. NO CPM - No detector signal in the counting circuit.

2. LOW FLOW - Flowrate drops below low flow setpoint.

Chapter 6, Page 111 of 170 Revision 20 OAG10000215_0820

IP2 FSAR UPDATE

3. T. TEAR - Particulate tape filter tears or the supply reel is run to empty.

4. LO TEMP - Monitor sample temperature is less than 10°F above containment air temperature. This alarm has been disabled.

5. WARN - Particulate or gas warn setpoint exceeded.

6. ALARM - Particulate or gas alarm setpoint exceeded.

6.7.1.2.4 Humidity Detectors The humidity detection instrumentation offers a means for the detection of leakage into the containment. The instrumentation is sensitive to vapor originating from all sources within containment, including the reactor coolant and steam and feedwater systems. Plots of changes in dewpoint of the containment atmosphere will be sensitive to incremental increases of water leakage to the containment atmosphere approximately 1.0 gpm/oF of dewpoint temperature increase (this sensitivity will vary with cooling water temperature, containment air temperature, and air recirculation rate). These detectors are located just upstream of each fan cooler unit. The information provided by this element and the temperature detector is used to determine the dewpoint in containment. This calculation is done automatically, and the resulting dewpoint information is recorded in the control room. The containment building high humidity alarm on the supervisory panel is initiated by the information being received by the recorder. 6.7.1.2.5 Condensate Measuring System This method of leak detection is based on the principle that under equilibrium conditions the condensate flow draining from the cooling coils of the containment air-handling units will equal the amount of water (and/or steam) evaporated from the leaking system. A reasonably accurate measurement of leakage from the reactor coolant system by this method is possible because containment air temperature and humidity promote complete evaporation of any leakage from hot systems. The ventilation system is designed to promote good mixing within the containment. During normal operation, the containment air conditions will be maintained below 120°F dry bulb and 92°F wet bulb (approximately 36-percent relative humidity) by the fan coolers. When the water from a leaking system evaporates into this atmosphere, the humidity of the fan cooler intake air will begin to rise. The resulting increase in the condensate drainage rate is given by the equation D = L [1 - exp (- Q t)] V Where: D =condensate drainage rate, gpm L = evaporated leakage, gpm Q = containment ventilation rate, cfm V = containment free volume, fe t =time after start of leak, min Therefore, if four fan cooler units are operating (Q = 280,000 cfm), the condensation rate would be within 5-percent of a new equilibrium value in approximately 200 min after the start of the Chapter 6, Page 112 of 170 Revision 20 OAG10000215_0821

IP2 FSAR UPDATE leak. The detection of the increasing condensation rate, however, would be possible within 5 to 10 min. The condensate measuring device consists essentially of a vertical 6-in. diameter standpipe with a notched weir cut into the upper portion of the pipe to serve as an overflow. Each fan cooler is provided with a standpipe, which is installed in the drain line from the fan cooler unit. A differential-pressure transmitter near the bottom of the standpipe is used to measure the water level. Each unit can be drained by a remote-operated valve. A wide range of flow rates can be measured with this device. Flows less than 1 gpm are measured by draining the standpipe and observing the water level rise as a function of time. Condensate flows from 1 gpm to 15 gpm are indicated in the central control room and can also be measured by observing the height of the water level above the notch of the weir. This water head can be converted to a proportional flow rate by means of a calibration curve. Flow rates greater than 15 gpm can also be determined using the calibration curves. A high-level alarm, set above the established normal (baseline) flow, is provided for each unit to alert the operator. All indicators, alarms, and controls are located in the control room. During the period of plant hot functional testing, a reactor coolant leak of known magnitude was simulated inside the containment vessel, and the performance of the humidity detector/condensate measuring system was observed. The leak was simulated by introducing steam into one of the loop compartments during a period when containment atmospheric conditions were stable and the fan cooler units were operating. The increase in containment atmosphere moisture content, as indicated by the humidity detectors, was recorded as a function of time following the initiation of the simulated leak. As a check, the same information was determined independently using different instrumentation. Elapsed time until condensation on the fan cooler unit cooling coils begins, as indicated by the condensate measuring devices, was recorded and compared with the calculated value on the basis of the initial containment humidity. Steam flow continued, and the performance of the condensate measuring devices in indicating the magnitude of steady cooling coil runoff was observed. 6.7.1.2.6 Component Cooling Liquid Monitor This channel continuously monitors the component cooling loop of the auxiliary coolant system for activity indicative of a leak of reactor coolant from either the reactor coolant system, the recirculation loop, or the residual heat removal loop of the auxiliary coolant system. A scintillation detector is installed in the local radiation monitor skid assembly. This assembly is located in the primary auxiliary building and receives sample flow from the component cooling pump discharge downstream of the component cooling heat exchangers. The detector assembly output is amplified by a preamplifier, processed and transmitted to the radiation monitoring system console, the safety related display console and a recorder in the control room. The activity is indicated on digital displays. High-activity alarm indications are displayed on the control board annunciator and the safety related display console. The measuring range of this monitor is 10-5 to 10-2 I-lCilcm 3 . 6.7.1.2.7 Condenser Air Ejector Gas Monitor This channel monitors the discharge from the air ejector exhaust header of the condensers for gaseous radiation that is indicative of a primary to secondary system leak. The gas discharge is routed to the turbine roof vent. On high-radiation-Ievel alarm, the condenser exhaust gases are diverted from the normal turbine building vent to the containment. Chapter 6, Page 113 of 170 Revision 20 OAG10000215_0822

IP2 FSAR UPDATE The processed detector output is transmitted to the radiation monitoring system console, the safety related display console and a recorder in the control room. The activity is indicated on digital displays. High-activity alarm indications are displayed on the control board annunciator and the safety related display console. This monitor is composed of an in-line spool piece, containing a normal range and an accident range detector. Each detector uses a beta sensitive scintillation detector to monitor the gaseous radiation level. Each detector includes adequate shielding to reduce interference with the detector's sensitivity caused by background radiation. The normal maximum channel output for this monitor is presented in Table 11.2-7. 6.7.1.2.8 Steam Generator Blowdown Liquid Sample Monitor This channel monitors the liquid phase of the secondary side of the steam generator for radiation, which would indicate a primary-to-secondary system leak, providing backup information to that of the condenser air ejector gas monitor. Samples from the bottom of each of the four steam generators are piped to a common header, and the mixed sample is continuously monitored by a scintillation counter and holdup tank assembly. Upon indication of a high-radiation level, each steam generator is individually sampled to determine the source. This sampling sequence is achieved by manually selecting the desired unit to be monitored and allotting sufficient time for sample equilibrium to be established (approximately 1 min). A remote indicator panel, mounted at the detector location, indicates the radiation level and high-radiation alarm. The measuring range of this monitor is 10-5 to 10-2 I-lCilcm 3 . A photomultiplier tube-scintillation crystal (Nal) combination, mounted in a hermetically sealed unit, is used to monitor liquid effluent activity. Lead shielding is provided to reduce the background to a level so it does not interfere with the maximum sensitivity of the detector. The in-line, fixed-volume container is an integral part of the detector unit. Personnel can enter the containment and make a visual inspection for leaks. The location of any leak in the reactor coolant system would be determined by the presence of boric acid crystals near the leak. The leaking fluid transfers the boric acid outside the reactor coolant system, and the process of evaporation deposits the crystals. If an accident involving gross leakage from the reactor coolant system occurred, it could be detected by charging pump operation, system and sump inventories, containment sump pump operation, containment radiation monitors, humidity detectors, and the condensate monitoring system. During normal operation, only one charging pump is operating. If a gross loss of reactor coolant to another closed system occurred, which was not detected by the methods previously described, the speed of the charging pump would indicate the leakage. The leakage from the reactor coolant system will cause a decrease in the pressurizer liquid level that is within the sensitivity range of the pressurizer level indicator. The speed of the charging pump will automatically increase to try to maintain the equivalence between the letdown flow and the combined charging line flow and flow across the reactor coolant pump Chapter 6, Page 114 of 170 Revision 20 OAG10000215_0823

IP2 FSAR UPDATE seals. If the charging pump at maximum speed is unable to maintain the required charging flow rate, then a pressurizer low level alarm actuates and a second charging pump may be started manually to maintain pressurizer level. A break in the primary system would result in reactor coolant flowing into the containment and/or recirculation sumps. Gross leakage to these sumps would be indicated by the frequency of operation of the containment sump pump(s) and containment water level indicators. Since the building floor drains preferentially to the containment sump, the activity of the containment sump pumps and/or containment sump level would be more likely to indicate the leak first. Gross leaks might be detected by an unscheduled increase in the amount of reactor coolant makeup water that is required to maintain the normal level in the pressurizer. A large tube-side to shell-side leak in the nonregenerative (letdown) heat exchanger would result in reactor coolant flowing into the component cooling water and a rise in the liquid level in the component cooling water surge tank. The operator would be alerted by a high-water alarm for the surge tank and a high-temperature alarm actuated by a monitor at the component cooling water pump suction header and a high-radiation alarm actuated by a monitor sampling the component cooling water pump discharge. A high-level alarm for the component cooling water surge tank and high-radiation and high-temperature alarms could also indicate a thermal barrier cooling coil rupture in a reactor coolant pump. However, in addition to these alarms, high temperature and low flow on the component cooling outlet line from the pump would activate alarms. Low thermal barrier component cooling water header return flow may be due to closure of FCV-625 on high flow or excessive usage by other loads. Gross leakage might also be indicated by a rise in the normal containment and/or recirculation sump levels. Level transmitters with control room indication are provided for each sump. 6.7.1.2.9 Residual Heat Removal Loop The residual heat removal loop removes residual and sensible heat from the core and reduces the temperature of the reactor coolant system during the second phase of plant shutdown. During normal operation, the containment air particulate and radioactive gas monitors, the condensate measuring system, and the containment sump inventory monitoring capability provide means for detecting leakage from the section of the residual heat removal loop inside the reactor containment. These systems have been described previously in this section (see the description of leak detection from the reactor coolant system). Leakage from the residual heat removal loop into the component cooling water loop during normal operation would be detected outside the containment by the component cooling loop radiation monitor (see the analysis of detection of leakage from the reactor coolant system in this section). The physical layout of the two residual heat removal pumps is within separate shielded and isolated rooms outside of the containment. This will permit the detection of a leaking residual heat removal pump by means of the plant vent gas monitoring system. Alarms in the control room will alert the operator when the activity exceeds a preset level. Small leaks to the environment could be detected with these systems within a short time after they occurred. When the plant is shut down, personnel can enter the containment to check visually for leaks. The detection of the location of significant leaks would be aided by the presence of boric acid Cha pter 6, Page 115 of 170 Revision 20 OAG10000215_0824

IP2 FSAR UPDATE crystals near the leak. In case of an accident that involves gross leakage from the part of the residual heat removal loop inside the containment, this leakage would be indicated by a rise in the containment and/or recirculation sump levels. Both of these sumps have level transmitters that provide level indication in the control room. Should a large tube-side to shell-side leak develop in a residual heat exchanger or the RH R pump seal heat exchanger, the water level in the component cooling surge tank would rise, and the operator would be alerted by a high-water alarm. A radiation monitor for the component cooling loop provides a high activity alarm. A temperature monitor at the component cooling water pump suction header will also signal an alarm. Leakage from both of the residual heat removal pumps, including leakage resulting from a residual heat removal pump seal failure, is drained to a common sump equipped with a sump pump. In addition, a level monitor in this sump will actuate an alarm when the level exceeds a preset level. 6.7.1.2.10 Recirculation Loop If a break occurs in the reactor coolant system, the recirculation loop provides long-term protection by recirculating spilled reactor coolant and injected refueling water. The containment air particulate and radioactive gas monitors, the humidity detectors, the condensate measuring system, and the containment sump inventory monitoring capability (see the section discussing leak detection for the reactor coolant system) provide means of detecting small leaks in the part of the recirculation loop inside the reactor containment. Leakage from the residual heat exchanger would be detected by a radiation monitor (discussed in the section on leak detection from the reactor coolant system) that receives sample flow from the component cooling water pump discharge downstream of the component cooling heat exchangers. During a containment entry personnel could check for leaks evidenced by the presence of boric acid crystals. Gross leakage from the recirculation loop inside the containment might be indicated by a rise in the level of the containment and/or recirculation sumps. Both of these sumps have level transmitters that provide level indication in the control room. A rise in the liquid level in the component cooling surge tank would result if a large tube-side to shell-side leak developed in a residual heat exchanger. The operator would be alerted by a high-level alarm in the component cooling water surge tank and a high-temperature alarm actuated by a monitor at the component cooling water pump suction header and a high-radiation alarm actuated by a monitor sampling the component cooling water pump discharge. Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. 6.7.1.2.11 Component Cooling Loop Leakage from the component cooling loop inside the reactor containment could be detected by the humidity detectors and/or condensate measuring system and the containment water level Chapter 6, Page 116 of 170 Revision 20 OAG10000215_0825

IP2 FSAR UPDATE indicators (see the section on reactor coolant system leak detection for a description of these systems). Visual inspection inside the containment is possible for some locations during containment entries. Gross leakage from the component cooling loop would be indicated inside the containment by a rise in the liquid level of the containment and/or recirculation sumps. Both of these sumps have level transmitters that provide level indication in the control room. Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. 6.7.1.2.12 Service Water System During a loss-of-coolant accident, the containment fan coolers service water monitors check the containment fan service water discharge line for radiation indicative of a leak from the containment atmosphere into the service water. A small bypass flow from each of the heat exchangers is mixed in a common header and monitored by redundant scintillation detectors mounted in separate holdup tank assemblies. Upon indication of a high-radiation level, each heat exchanger is individually sampled to determine which unit is leaking. This sampling sequence is achieved by manually selecting the desired unit to be monitored and allotting sufficient time for sample equilibrium to be established (approximately 1 min). The discharge line from the fan coolers motor coolers is also monitored for radioactivity and isolated in a like manner following the detection of a leak. The measuring range of this monitor is 10-5 to 10-2 I-lCilcm 3 . Gross leakage from the service water system due to a faulty cooling coil in the containment air recirculation cooling system can be detected by weir level transmitters. Any significant cooling water leakage would be seen as flow into a fan cooler unit weir. Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. 6.7.1.2.13 Containment Sump Level The sump flow detection system includes flow metering and totalizing that is indicated in the control room. IrlC3~~itiont()thE3()riginal plant level transmitters (LT-940 and LT-941), redundant level M§iM§mi"tt@fI.;1H9$Q4D§i§ been installed to provide a more accurate method of measuring water level in the sump. These levels are indicated in the control room on the accident assessment panel. [P~I~t§q] Another level instrument qualified to Class 1E, IEEE-323-197 4, and IEEE-344-1975 is provided for continuous level indication (LT-3300). Additionally, existing level monitor (LT-941) was upgraded to meet environmental qualification requirements to support minimum NPSH requirements for recirculation pump start. Chapter 6, Page 117 of 170 Revision 20 OAG10000215_0826

IP2 FSAR UPDATE Sump level is maintained by the action of containment sump pumps. The pumps are independently powered and have separate power and control cables to each pump. 6.7.1.2.14 Recirculation Sump Level Water may also collect in the recirculation sump although under most circumstances the containment sump will be filled before the recirculation sump. Water level monitoring of the recirculation sump is provided by two level instruments, which actuate control room lights at discrete sump/containment water levels and provide an audible alarm for certain discrete levels within the recirculation sump. Level monitor LT-939 is environmentally qualified to support minimum NPSH requirements for recirculation pump start. A continuous level monitor is also provided for wide-range level indication. 6.7.1.2.15 Reactor Cavity Pit Level The level in the reactor cavity pit is controlled through the action of reactor cavity pit pumps that are used to pump to the containment sump any water that may have leaked into the pit. The system is designed for usage during refueling/maintenance outages. Four alarms are located in the central control room on panel SB-1: Reactor Cavity Pit Water Level High (LC-7049) Reactor Cavity Pit Water Level High-High (LC-7049) Reactor Cavity Sump Pit Pump No. 1 Auto Run (LC-7043) Reactor Cavity Sump Pit Water Level High (LC-7042) LC-7042 and LC-7043 control Reactor Cavity Sump Pit Pump No.1. LC-7049 controls Reactor Cavity Pit Pump No.2. A continuous level monitor (LT-3302) is also provided for wide-range level indication within the reactor cavity pit. The reactor cavity pit pumps are independently powered and have separate control wiring. 6.7.2 Leakage Provisions Provisions are made for the isolation and containment of any leakage. 6.7.2.1 Design Basis The provisions made for leakage are designed to prevent uncontrolled leaking of reactor coolant or auxiliary cooling water. This is accomplished by (1) isolating the leak by valves, (2) designing relief valves to accept the maximum flow rate of water from the worst possible leak, (3) supplying redundant equipment that allows a standby component to be placed in operation while the leaking component is repaired, and (4) routing the leakage to various sumps and holdup tanks. 6.7.2.2 Design and Operation Various provisions for leakage avert uncontrolled leakage from the primary and auxiliary coolant loops. Chapter 6, Page 118 of 170 Revision 20 OAG10000215_0827

IP2 FSAR UPDATE 6.7.2.2.1 Reactor Coolant System When significant leakage from the reactor coolant system is detected, action is taken to prevent the release of radioactivity to the atmosphere outside the plant. If either the containment air particulate gamma activity or the radioactive gas activity exceeds preset levels, the containment purge supply and exhaust duct valves and pressure relief line valves are closed, if open. On high-radiation alarm signaled by the condenser air ejector monitor, the condenser exhaust gases are diverted from the turbine roof vent to the containment. A high-radiation alarm actuated by the steam-generator liquid sample monitor initiates the closure of the isolation valves in the blowdown lines. A sample stop valve and a blowdown tank inlet stop valve located downstream of each pair of isolation valves will automatically close when either of their associated blowdown line isolation valves leaves its fully open position in order to isolate their respective lines. If the component cooling loop radiation monitor signals a high-radiation alarm, the valve in the component cooling surge tank vent line automatically closes to prevent gaseous activity release. If a leak from the reactor coolant system to the component cooling loop were a gross leak or if the leak could not be isolated from the component cooling loop before the inflow completely filled the surge tank, the relief valve on the surge tank would open. The discharge from this valve is routed to the waste holdup tank in the primary auxiliary building. A large leak in the reactor coolant system pressure boundary, which does not flow into another closed loop, would result in reactor coolant flowing into the containment sump and/or the recirculation sump. Experience with the detection of primary system leakage into the containment vessel of Indian Point Unit 1 is discussed in Appendix 68. 6.7.2.2.2 Residual Heat Removal Loop High containment air particulate gamma activity or high radioactive gas activity will result in an alarm being activated by either the containment air particulate or radioactive gas monitors. The containment purge supply and exhaust duct valves and pressure relief line valves are closed automatically, if open. This prevents the release of radioactivity to the atmosphere outside the nuclear plant. If leakage from the residual heat removal loop into the component cooling loop occurs, the component cooling radiation monitor will actuate an alarm and the valve in the component cooling surge tank vent line is automatically closed to prevent gaseous radioactivity release. If the leaking component (i.e., a residual heat exchanger) could not be isolated from the component cooling loop before the inflow completely filled the surge tank, the relief valve on the surge tank would open and the effluent would be discharged to the primary auxiliary building waste holdup tank. Cha pter 6, Page 119 of 170 Revision 20 OAG10000215_0828

IP2 FSAR UPDATE Gross leakage from the section of the residual heat removal loop inside the containment, which does not flow into another closed loop would result in reactor coolant flowing into the containment sump and/or the recirculation sump. Other leakage provisions for the residual heat removal loop are discussed in Section 9.3. 6.7.2.2.3 Recirculation Loop The containment purge supply and exhaust duct valves and pressure relief line valves are automatically closed, if open, when either the containment air particulate or the radioactive gas monitors read above a preset level. This prevents radioactivity from escaping to the outside atmosphere. Leakage from the recirculation loop into the component cooling loop results in a radiation alarm and the automatic closing of the component cooling surge tank vent line to prevent gaseous radioactivity release. If the leak were gross and filled the surge tank before the leaking component could be isolated from the component cooling loop, the relief valve on the surge tank would open and the effluent would be discharged to the waste holdup tank in the primary auxiliary building. Gross leakage from the internal recirculation loop, which does not flow into another closed loop will flow into the containment sump and/or the recirculation sump. Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. 6.7.2.2.4 Component Cooling Loop Gross leakage from the section of the component cooling loop inside the containment, which does not flow into another closed loop will flow into the containment sump and/or the recirculation sump. Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. Other provisions made for leakage from the component cooling loop are discussed in Section 9.3. 6.7.2.2.5 Service Water System Leakage outside containment depending on location will be diverted by floor drains to either the PAB sump tank or PAB sump where it will then be transferred to the Waste Holdup Tank. 6.7.3 Minimum Operating Conditions The Technical Specifications establish limiting conditions regarding the operability of the leakage detection systems. Chapter 6, Page 120 of 170 Revision 20 OAG10000215_0829

IP2 FSAR UPDATE TABLE 6.7-1 Class 1 Fluid Systems For Which No Special Leak Detection Is Provided System Remarks On Leakage Detection

1. Residual heat removal Refer to items 1, 2, and 3 (Section 6.7.1.2) and Section 6.7.1.2.9.

2. Component cooling Refer to items 2 and 3 (Section 6.7.1.2) and Section 6.7.1.2.11

3. Service water Refer to item 3 (Section 6.7.1.2) and Section 6.7.1.2.12

4. Auxiliary feedwater Visual

5. Waste disposal Auxiliary building sump pump operation.

Also refer to item 1 (Section 6.7.1.2) 6.8 POSTACCIDENT HYDROGEN CONTROL SYSTEMS 6.8.1 Design Basis The function of the hydrogen control system is to control the hydrogen generated within the containment following a loss-of-coolant accident. A Hydrogen Recombiner System is provided to control the post-accident hydrogen concentration in containment. The Hydrogen Recombiner System uses two redundant safety-related Passive Hydrogen Recombiners (PHR). Each recombiner unit is capable of maintaining the hydrogen concentration at or below 4 volume percent. The flame type recombiners system installed originally has been retired in place within the containment building and the associated containment isolation valves have been de-energized in closed position. The post-accident containment venting system provides a backup method to containment recombiners for controlling the potential hydrogen accumulation in the containment. This is accomplished by the controlled venting of containment atmosphere to maintain the hydrogen concentration at a safe level. The venting system is designed to limit the hydrogen concentration below 4 volume percent. Chapter 6, Page 121 of 170 Revision 20 OAG10000215_0830

IP2 FSAR UPDATE A containment air sample is taken from each of the containment fan cooler units at a point located downstream from the fan. Sample analysis will determine the requirement for the post-accident containment venting system operation. 6.8.2 System Design and Operation 6.8.2.1 Passive Hydrogen Recombiners Two 100% capacity independent hydrogen recombiners are provided. The recombiners are passive devices, which contain no moving parts and do not need electrical power or any other support system. Recombination is accomplished by the attraction of oxygen and hydrogen molecules to the surface of the catalyst, Reference 3. The PHRs used at IP 2 are Passive Autocatalytic Recombiners (PARs) designed and manufactured by NIS Ingenieurgesellschaft mbH of Germany (NIS). The PHR consists of a stainless steel sheet metal box open at the bottom and at both sides on the top as shown on Figure 6.8-1. The approximate size of the box is 1m x 1m x 1m. There are 88 catalytic cartridges inserted into each box. Each cartridge fabricated from perforated steel plates holds catalyst pellets. The catalyst pellets are made from aluminum oxide spheres and are coated with palladium and hydrophobic polymers. The palladium coating acts as a catalyst and the hydrophobic coating provides water proofing. The catalyst cartridges are installed vertically, spaced 1 cm apart, in each box. The spaces between the cartridges serve as flow channels for the gases. Airflow enters at the bottom and the catalyst combines hydrogen and oxygen in the flow channels to form gaseous water. PHRs are designed for self-starting and self-sustaining reaction. The exothermic reaction of the combination produces heat, which results in a convective flow that draws more gases from the containment atmosphere into the unit from below. A single recombiner is capable of maintaining the hydrogen concentration in containment below the 4 volume percent flammability limit. The second recombiner is redundant and is installed to provide margin and increased containment coverage. PHRs are safety related and are seismic class I, and have undergone environmental qualification testing in accordance with IEEE 627 and IEEE 344. 6.8.2.2 Containment Vent System The postaccident containment venting system consists of a common penetration line that acts as a supply line through which outside air can be admitted to the containment, and an exhaust line, with parallel valving and piping, through which hydrogen-bearing gases from containment may be vented through a filter. The system is shown in Figure 6.8-3. The supply mode makes use of instrument air to feed containment. The nominal flow rate from either of the two instrument air compressors is 225 scfm. In the exhaust mode, the line penetrates the containment and then is divided into the parallel lines. Each parallel line contains a pressure sensor and all the valves necessary for controlling the venting operation. The two lines then rejoin and the exhaust passes through a flow sensor and a temperature sensor before passing through charcoal and HEPA filters. The exhaust is then directed to the plant vent. Chapter 6, Page 122 of 170 Revision 20 OAG10000215_0831

IP2 FSAR UPDATE The venting system requires a differential pressure between the containment and the outside atmosphere in order to permit venting. This is based on a pressure of 2.14 psig in the containment. If required, the containment is pressurized to 2.14 psig with instrument air when the hydrogen reaches 3 volume percent after the loss-of-coolant accident. The hydrogen concentration is reduced by this pressurization. Purging is then delayed until the hydrogen concentration in the containment has once again built up to 3 volume percent. 6.S.2.3 Containment Air Analyzer System Two hydrogen/oxygen analyzers have been installed to continuously monitor the hydrogen and oxygen concentrations in the containment atmosphere. A new system of valves, controlling equipment, and a central control room display have also been installed to replace the old method of manual containment air sampling. This system functions independently of the original vacuum pump (which has been isolated) and provides the required sampling capability under NUREG-0737, Item II.B.3. The containment atmosphere sampling system was evaluated by the NRC against the NUREG-0737 requirements and found acceptable. 1,2 The requirements for the containment atmosphere sampling system were removed from the Technical Specifications by License Amendment No. 222 as discussed in Section 9.4.1.1. The system is shown in Plant Drawing 20S479 [Formerly UFSAR Figure 6.S-4]. The system has a closed-loop flow path with the sampled air withdrawn from and discharged to the containment. The operation of the system is from remote control panels located in the motor control center room at elevation 9S-ft of the primary auxiliary building. The new solenoid-operated valves function to both pass a sample for analyzing and to provide containment isolation when not sampling or during an accident. The hydrogen/oxygen analyzers are located on elevation SO-ft of the primary auxiliary building. Direct indicator readout is provided in the 9S-ft motor control center room in the primary auxiliary building. The hydrogen/oxygen values are indicated and recorded on two recorders located on the control room accident assessment panel. One recorder is used for each channel. Nitrogen purging capability of the sample lines is also provided. The purging reduces line activity and radiation field in the primary auxiliary building after a sample is drawn. The purge is so arranged that it is sent back to the containment. All equipment is procured and installed Class A, seismic Class I. The recorders, solenoid-operated valves and other electrical equipment are Class 1E. The eight solenoid-operated valves provided with this system are powered from four separate dc power supplies and configured so that the system meets single-failure criteria both for the path opening (i.e., sampling) and for the path closing (i.e., containment isolation) safety functions. 6.S.2.4 System Operation PHRs are located inside the containment, they are totally passive, and are self-starting self-feeding devices. No operator action is required to initiate recombination of accident hydrogen with containment oxygen. 6.S.3 Postaccident Hydrogen Generation During the postaccident period, hydrogen is generated in the containment from the following sources: Chapter 6, Page 123 of 170 Revision 20 OAG10000215_0S32

IP2 FSAR UPDATE

1. Zirconium-water reaction.

2. Chemical reaction of materials subject to corrosive attack.

3. Radiolytic decomposition of coolant in the core.

4. Radiolytic decomposition of coolant in the sump.

These results are shown in Plant Drawings 9321-2568 & -2569 [Formerly UFSAR Figure 6.8-2] for the first 30 days of the post-accident period and have been obtained on the following bases. 6.8.3.1 Zirconium-Water Reaction

1. Five percent of the core cladding reacts immediately with core cooling solution according to the reaction Zr + H 20 ~ Zr02 + H2 +heat

2. There are 44,197 Ibm of zirconium cladding in the core.

6.8.3.2 Corrosion of Materials of Construction

1. Corrosion of aluminum and zinc according to the reactions

2. Aluminum and zinc corrosion rates versus time postaccident Time AI Corrosion Rate Zn Corrosion Rate (days) (mil/yr) (mil/yr) 0.0 5,500 180 0.0035 1,700 180 0.0116 600 160 0.0232 200 110 0.0464 200 20 20 200 20

3. Aluminum available for reaction as follows:

Item Mass Area Thickness l!Ql (fel (inch) Control rod drive mechanism 25 14 0.207 connectors Reactor vessel insulation foil 269 10,000 0.0019 Area monitors 6 4 0.107 Source, intermediate, and 140 40 0.245 power range detectors Process instrumentation and 420 84 0.356 controls Lighting fixtures and 1061 380 0.199 Chapter 6, Page 124 of 170 Revision 20 OAG10000215_0833

IP2 FSAR UPDATE equipment Paint on steam generator, 140 10,000 0.001 pressurizer, and reactor vessel Contingency 2500 850 0.209

4. A contingency for zinc available for reaction was made by assuming a 20,000 square-foot surface, thick enough (0.065 inch) to not corrode all the way through in 30 days.

6.8.3.3 Core Radiolysis Regulatory Guide 1.7, Rev.2, "Control ot Combustible Gas Concentrations in Containment Following a Loss-ot-Coo/ant Accident" describes methods acceptable to the NRC staff for implementing the requirements of 10 CFR 50.44. For Indian Point 2, the core and sump radiolysis analyses have been done in accordance with that Guide. In summary, the effects of core radiolysis are as follows:

1. 50-percent of the halogens, 100-percent of the noble gases, and 99-percent of all other fission products are retained in the core following the accident.

2. 0.50 molecules of hydrogen are generated per 100 eV of energy absorbed by water in the core.

3. 10.0-percent of the core fission product gamma energy is absorbed by the solution in the core.

4. Beta energy is absorbed by the fuel and cladding and does not contribute to hydrogen generation in the core.

5. Core fission product decay energy is calculated in accordance with Branch Technical Position ASB 9-2, as originally implemented in the COGAP computer code and transferred to STARGAP.

6. The plant is operational for 830 days at 3216 MWt before the accident.

6.8.3.4 Sump Radiolysis

1. 50-percent of the halogens, none of the noble gases, and 1-percent of all other fission products are released from the core to the sump during the accident.

2. 0.50 molecules of hydrogen are generated per 100 eV of energy absorbed by the sump solution.

3. All beta and gamma energy emitted by fission products in the sump solution are absorbed and contribute to hydrogen generation.

4. The plant is operational for 830 days at 3216 MWt before the accident.

Chapter 6, Page 125 of 170 Revision 20 OAG10000215_0834

IP2 FSAR UPDATE 6.8.4 Evaluation To evaluate the potential for hydrogen accumulation in containment following a LOCA, the hydrogen generation as a function of time following the initiation of the accident is calculated. Assumptions recommended by Reference 6 are used to maximize the amount of hydrogen calculated. The hydrogen release to containment is graphically presented in Plant Drawings 9321-2568 & -2569 [Formerly UFSAR Figure 6.8-2]. It will take more than 20 days after a LOCA for the hydrogen concentration in the containment to reach 4.0 volume percent, if no recombiner was functioning. The PHRs are designed such that, a single recombiner is capable of limiting the peak hydrogen concentration in containment to less than 4.0 volume percent. Two PHR are located on the operating deck at an approximate elevation of 29 m (95 feet) out side the missile shield wall. This location is away from the reactor coolant piping and possible impingement from high-energy line breaks. Mixing of the hydrogen in containment is ensured through the use of the containment fan coolers. Three to five fan coolers operate in the post-accident environment. The capability of the fan coolers is described in Section 6.4. The flow distribution from fan coolers is directed to various locations including locations high in containment. Both PHRs are mounted on the open grating to allow free airflow through the PHRs. The housing extends above the catalyst elevation to provide a chimney to yield additional lift to enhance the efficiency of the device. One condition that is to be avoided for proper PHR functioning is submersion in water. The PHR are located above the containment flood level and they are designed with a spray hood to minimize the direct contact with the post-accident containment sprays. Since PHRs are credited for post-LOCA hydrogen control the effects of potential catalyst inhibitors and poisons present during the accident conditions were accounted for. The Electric Power Research Institute (see Reference 5) has evaluated the effects of potential catalyst inhibitors and poisons. Limited decreases in catalyst effectiveness were noted. Any decrease in effectiveness is more than compensated for by the combination of conservative hydrogen generation assumptions and substantial excess installed PHR capacity. 6.8.4.1 Qualification Testing As a prerequisite for final installation of PHRs at Indian Point 2, environmental qualification tests were performed at Wyle Laboratories in accordance with the applicable requirements of 10CFR21, 10CFR50 Appendix B, and ANSI N45.2. Sample cartridges from equipment device designed and built by NIS Ingenieurgesellschaft mbH (NIS) supplied for Indian Point 2 were subjected to the qualification testing. The results of these tests were submitted to NRC and NRC approved (Reference 4) the use of NIS PARs at Indian Point 2. The details of these tests, the acceptance criteria and the results are documented in the Wyle test report, which is filed in Indian Point EQ files. 6.8.5 Inspections And Tests A visual examination and an operating check of the system is performed periodically, as specified in the Technical Specifications. Visual examination and cleaning if necessary is performed at each refueling outage to verify that there is no significant fouling by foreign Chapter 6, Page 126 of 170 Revision 20 OAG10000215_0835

IP2 FSAR UPDATE material. Performance of a test on a sample plate removed from each hydrogen recombiner at each refueling outage ensures the recombiners are operational. The sample plate removed from each recombiner is inserted into a test device and a fixed flow mixture of gas that is 1% to 1.5% hydrogen in air is supplied to the device. The plate is judged to be degraded if the temperature developed is not within the acceptance criteria. In this case the neighboring plate will be tested. Any plates found to be degraded will be evaluated or replaced with new plates. 6.8.6 Minimum Operating Conditions Operability requirements for the PHRs were removed from the Technical Specifications by license amendment #243. REFERENCES FOR SECTION 6.8

1. Letter from S. A. Varga, NRC, to J. D. O'Toole, Con Edison,

Subject:

Postaccident Sampling at the Indian Point Unit 2, Safety Evaluation Report, dated June 28, 1984.

2. Letter from S. A. Varga, NRC, to J. D. O'Toole, Con Edison,

Subject:

Postaccident Sampling at the Indian Point Unit 2, Safety Evaluation Report, dated December 12, 1984.

3. S. E. Quinn to Document Control Desk, USNRC, "Proposed Technical Specification for H2 Recombiners", August 21, 1996.

4. Letter from Jeffrey F. Harold, NRC to A. Alan Blind, Con Edison "Issuance of Amendment and Bases Change for Indian Point Nuclear Generation Unit No.2 (TAC No. M96475)", dated April 27,1999.

5. EPRI ALWR Report GC-108771 "Effects of Inhibitors and Poisons on the Performance of Passive Autocatalytic Recombiners (PARs) for Combustible Gas Control in ALWRs",

June 28, 1999.

6. Regulatory Guide 1.7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident (Rev. 2) 7.

6.8 FIGURES Figure No. Title Figure 6.8-1 Passive Hydrogen Recombiners Figure 6.8-2 Containment Hydrogen vs Time Post-LOCA - Replaced with Plant Drawings 9321-2568 & 9321-2569 Figure 6.8-3 Postaccident Containment Venting System - Flow Diagram, Replaced with Plant Drawing 208879 Figure 6.8-4 Postaccident Containment Sampling System - Flow Diagram, Replaced with Plant Drawing 208479 Chapter 6, Page 127 of 170 Revision 20 OAG10000215_0836

IP2 FSAR UPDATE APPENDIX6A EFFECTIVENESS OF THE CONTAINMENT SPRAY SYSTEM TO REMOVE AIRBORNE ACTIVITY FOLLOWING A LOCA In the event of a postulated Loss-of-Coolant Accident (LOCA) with degraded core, there would be a substantial release of core fission product activity to the containment atmosphere. The core degradation source term is assumed to release the following fractions of core activity to the containment atmosphere consistent with the source term described in Regulatory Guide 1.183 (Reference 1): Noble gases 1.0 lodines 0.4 Alkali metals 0.3 Tellurium group 0.05 Barium & Strontium 0.02 Noble metals 0.0025 Cerium group 0.0005 Lanthanides 0.0002 With the exception of the noble gases, the activity released to the containment atmosphere is subject to removal by the containment spray system. As defined in Regulatory Guide 1.183, the iodine activity entering the containment atmosphere is assumed to exist primarily as an aerosol (95% of the iodine is assumed to be in the form of cesium iodide) with the remainder existing as elemental iodine vapor (4.85%) or as organic compounds (0.15%). The activity for the remaining nuclide groups is assumed to all be in the aerosol form. The containment spray system is one of the engineered safety features systems employed following a LOCA to reduce the pressure and temperature in the containment. The spray system also affords an excellent means of removing both elemental iodine vapor and aerosols from the containment atmosphere. Organic iodine compounds are assumed not to be subject to removal by sprays. During the spray injection phase the spray consists of boric acid solution taken from the refueling water storage tank. This spray solution has a pH of -4.5 - 5.0. While sprays are an effective means to remove airborne iodine, retention of iodine in the sump solution requires that the solution pH be raised to 7.0 or above. This pH adjustment is provided by the trisodium phosphate stored in baskets in the sump area (See Section 6.3). The removal of airborne activity by the containment sprays is expressed by the following equation which calculates the amount of activity remaining at a given time: (6A-1) where: C =Current activity, Ci Co = Initial activity, Ci As =Spray removal coefficient, h(1 Chapter 6, Page 128 of 170 Revision 20 OAG10000215_0837

IP2 FSAR UPDATE t =time, hr 6A.1 SPRAY REMOVAL COEFFICIENT FOR PARTICULATES The spray removal coefficient for particulates is determined using the model described in SRP Section 6.5.2 (Reference 2): Ap =3hFE I 2VD (6A-2) where: Ap = Particulate removal rate constant due to spray removal, h(1 h = Drop fall height, ft F = Spray flow rate, fe/hr V = Volume Sprayed, fe E = Single drop collection efficiency D = Drop diameter, ft The value for E/D is conservatively defined in SRP Section 6.5.2 to be 10 m- 1 (3.048 fr1) initially and is reduced by a factor of 10 after the suspended aerosol mass has been depleted by a factor of 50 (i.e., after 98% of the aerosols have been removed). Spray Fall Height and Sprayed Volume The spray system nozzle and header arrangement is designed to cover a maximum area in the upper containment. Four headers, arranged in concentric circles, are located in the containment dome at elevations of 213.5,218.6,223.6, and 228.6 feet. Credit is taken for spray coverage of the total volume above the operating deck. The spray fall height from the lowest of the spray headers is 118.5 feet. It is conservatively assumed that all spray falls through the same distance (ignoring the additional fall-time associated with the higher spray headers). The sprayed volume is 80 percent of the containment free volume (i.e., 2.088 x 106 cubic feet). Containment Spray Flow Rate During the spray injection phase it is assumed that only one of the two spray pumps is operating, drawing water from the refueling water storage tank. The minimum spray flow rate is 2135 gpm (17,646 ft3/hr) for one spray pump under design basis accident conditions. Once the inventory of the refueling water storage tank is depleted, there is a switch to the recirculation spray phase. The containment spray pump is not used during the spray recirculation phase; instead, the flow to the spray headers is obtained from the recirculation pump which recirculates water from the sump to the reactor vessel. The system resistance provided by the physical configuration of the recirculation piping and components is hydraulically balanced such that sufficient flow is established to the core and to the spray headers. The minimum recirculation spray flow rate of 1100 gpm (8823 fe/hr) is half the injection spray flow rate. Chapter 6, Page 129 of 170 Revision 20 OAG10000215_0838

IP2 FSAR UPDATE Spray Removal Coefficient Using the above-defined values, the spray removal coefficient for aerosols is determined as follows: Ap =3hFE I 2VD Injection Phase: Recirculation Phase: Ap =2.2S h(1 These values are reduced by a factor of 10 once the aerosol inventory is reduced to two percent of the total aerosol inventory released to the containment atmosphere. 6A.2 SPRAY REMOVAL COEFFICIENT FOR ELEMENTAL IODINE The original design of the containment spray system included spray additive (sodium hydroxide) to increase the pH of the boric acid solution to approximately 9.S. The purpose of the pH adjustment was to increase spray removal of elemental iodine. However, as discussed in SRP Section 6.S.2 (Reference 2), it has been determined that the boric acid spray without pH adjustment to alkaline conditions is an effective means to remove airborne elemental iodine. The spray removal coefficient for elemental iodine is determined using the model described in SRP Section 6.S.2: As =6KgtF I VD (6A-3) where As = Elemental iodine removal rate constant due to spray removal, h(1 Kg =Gas phase mass transfer coefficient, ftlmin t = Average spray droplet fall time, min F = Spray flow rate, fe/hr V = Volume sprayed, fe o = Average drop diameter, ft The values for spray flow rate and sprayed volume are defined in Section 6A.1. The gas phase mass transfer coefficient (Kg) is conservatively defined as 3 m/min (9.0S4 ftlhr) in Reference 3 based on a number of experimental studies. SRP Section 6.S.2 specifies an upper limit for As of 20 h(1 for fresh solution. Drop Diameter There is a spectrum of drop sizes in the containment atmosphere at any time. Measurements of the drop size distribution of the Sprayco 1713 nozzle have shown that the drop size varies between SO and 3S00 Ilm, with -SO percent of the generated drops being SOO Ilm or smaller (Reference 4). The initial distribution of drops after release from the nozzles is affected during the fall through the containment atmosphere by coalescence and by condensation of steam onto the drops. The increase in drop size associated with condensation increases the total Chapter 6, Page 130 of 170 Revision 20 OAG1000021S_0S39

IP2 FSAR UPDATE surface area of the droplets that would be available for absorbing iodine. While coalescence of drops also increases individual droplet size, it decreases the number of droplets and thus decreases the total surface area of the airborne droplets. Increases in droplet size also decrease the fall time during which the drops are available to remove elemental iodine from the containment atmosphere. Since the spray droplets enter the containment at temperatures far below that of the initial temperature of the containment atmosphere, condensation of steam from the containment air-steam mixture will increase the initial size of the drops until they are in thermal equilibrium with the ambient. From an energy balance on the drop: mh + me hg =m'hf (6A-4) where: m = mass of drop before condensation h =enthalpy of drop at spray inlet temperature me = mass of condensed steam m' = mass of drop after condensation hg = saturation vapor enthalpy at containment condition hf = saturation liquid enthalpy at containment condition From a mass balance: me =m' - m Substituting into equation 6A-4: mh + (m' - m)h g = m'hf or: m'/m =(h g - h)/(h g - hf) where v is the specific volume at inlet conditions and Vf is the specific volume at containment conditions. The increase in the drop radius due to condensation then is: (6A-5) Just as the spray droplets can remove aerosols from the containment atmosphere, the droplets are capable of removing other droplets. This collision and resulting coalescence result in an increase in the average drop size. Coalescence efficiency is the probability that a collision between two drops will result in the formation of a single larger drop. It is conservatively assumed that all droplet collisions result in coalescence. This is a very conservative assumption which results in the prediction of an average droplet size significantly larger than would be expected to occur. Cha pter 6, Page 131 of 170 Revision 20 OAG10000215_0840

IP2 FSAR UPDATE Taking the effects of coalescence and condensation into consideration, the value for the mean droplet diameter is 1200 I-lm (3.94E-3 ft). Spray Droplet Fall Time One of the simplifying assumptions of the model is that the residence time of the drop in the containment atmosphere may be approximated by fall height divided by the terminal velocity of the drop (h/U,). However, the actual residence time of the drop is considerable longer, since the drops do not leave the nozzle with only a vertical velocity component, but with an additional horizontal component, which causes the droplets to fall along a trajectory, which increases the residence time of the droplet. (This fact is further amplified by the 45-degree nozzles.) Thus, the use of h/U" combined with defining the spray fall height as the fall height for the lowest elevation spray ring header, adds further conservatism to the model. This model gives a minimum residence time of 10.7 seconds for a 1200 I-lm drop. Spray Removal Coefficient Using the above-defined values, the spray removal coefficient for aerosols is determined as follows: As =6KgtF I VD Injection Phase: The calculated value of 22.5 h(1 is reduced to 20 h(1 consistent with the upper limit defined in SRP Section 6.5.2. Recirculation Phase: As= 5.6 h(1 The calculated value of 11.2 h(1 is reduced by 50% to 5.6 h(1 to address the loading of the recirculating solution with elemental iodine. 6A.3 LIMITS OF REMOVAL There is no defined limit in SRP Section 6.5.2 on the removal of aerosols from the atmosphere. A conservative approach, which is used for Indian Point Unit 2, is to limit credit for aerosol removal to a OF of 1000 (i.e., 0.1 % of the original inventory release to the containment atmosphere remaining airborne). If recirculation spray is terminated prior to reaching this limit, sedimentation will continue to remove aerosols until the OF limit is reached. The removal rate associated with sedimentation is addressed in Section 14.3.6.1. SRP Section 6.5.2 specifies a limit on elemental iodine removal of a OF of 200 (i.e., 0.5% of the original inventory release to the containment atmosphere remaining airborne). This is dependent on the sump solution pH being adjusted to 2::7.0. As discussed in Section 6.3.2, the mass of trisodium phosphate stored in the containment is sufficient to assure that following a LOCA a sump solution pH of 2::7.0 is achieved and maintained. Chapter 6, Page 132 of 170 Revision 20 OAG10000215_0841

IP2 FSAR UPDATE REFERENCES FOR APPENDIX 6A

1. USNRC Regulatory Guide 1.183, "Alternative Radiological Source Terms for Evaluating Design Basis Accidents at Nuclear Power Reactors," July 2000.

2. NUREG-0800, USNRC Standard Review Plan, Section 6.5.2, "Containment Spray as a Fission Product Cleanup System," Revision 2, December 1988.

3. R. E. Davis, H. P. Nourbakhsh, and M. Khatib-Rahbar, "Fission Product Removal Effectiveness of Chemical Additives in PWR Containment Sprays," Technical Report A-3788, Brookhaven National Laboratory, 8/12/86.

4. WCAP-8659, "CIRCUS Computer Code - Calculation of Vapor Phase Elemental Iodine Removal in the Reactor Containment by Chemical Additive Spray," June 1975, (Westinghouse Proprietary)

APPENDIX6B PRIMARY SYSTEM LEAK DETECTION INTO CONTAINMENT VESSEL, INDIAN POINT UNIT 1 Table of Contents Section and Title 6B.O Operational Experience 6B.1 Assumptions 6B.2 Basic Data Used for Calculations 6B.3 Sample Calculations Chapter 6, Page 133 of 170 Revision 20 OAG10000215_0842

IP2 FSAR UPDATE 6B.0 OPERATIONAL EXPERIENCE During the lifetime of Indian Point 1, primary system leakage was minimal. A combination of all the following instrumentation was used to detect several leaks ranging in size from 0.1 to 3 gal/hr. However, because of the magnitude of these leaks, positive identification resulted only from visual inspection during containment entries made after scheduled plant shutdown. Small leaks that developed in the primary system pressure boundary could be detected by several continuously recording instruments available to the plant operators. The most sensitive of these detectors was the radioactive air particulate monitor, which continuously sampled the air in the containment cooling system. The purpose of the containment cooling system was to maintain proper ambient temperatures for equipment in the containment vessel. This system took air from the upper elevations of the vessel and recirculated it through cooling coils on the suction side of the supply fan. This air was then discharged at a rate of 40,000 cfm through steam coils. The turnover rate of the containment vessel as a result of this system was approximately once every hour. By sampling air from the discharge of the containment cooling system supply fan, leak rates as small as 0.3 gal/hr (20 cm 3/min) could be detected. Another detector, the radiogas monitor, sampling air from the same position as the air particulate monitor, continuously analyzed air from the containment cooling system for gaseous radioactivity. This monitor was capable of detecting a leak rate of about 100 gal/hr (6500 cm 3/min). In addition to measuring changes in the radioactivity of the containment vessel, dewpoint sensors continuously sampled the air from the suction side of the containment cooling system supply fans. These instruments could detect a primary coolant leak rate of approximately 4 gal/hr (250 cm 3/min) by measuring changes in the moisture content of the containment vessel. By the use of the above instruments, plant operators could continuously monitor the containment vessel for primary system leakage and take any steps necessary to operate the facility safely. Measurements made by the New York University Medical Center, Institute of Environmental Medicine, have shown that the samples analyzed by these instruments are representative of the containment vessel and that samples take manually to backup these detectors were accurate to within a factor of 2. Other methods for detecting and locating primary system leakage included visual inspection for escaping steam or water, boric acid crystal formation, component and primary relief tank levels, hydrogen concentration and radioactivity, containment sump level, and manual samples for tritium radioactivity in condensed moisture from the containment vessel. 6B.1 ASSUMPTIONS

1. Uniform mixing in containment occurs within 1 hr after a leak, based upon one containment cooling fan in service at 40,000 cfm.

2. The smallest significant changes instrumentation are as follows:

a. Radiogas monitor on the containment cooling system 1 count per sec is equivalent to 3 x 10-7 pCilcm 3 Chapter 6, Page 134 of 170 Revision 20 OAG10000215_0843

IP2 FSAR UPDATE

b. Particulate monitor 8 counts per sec is equivalent to 8 x 10-9 pCilcm 3

c. Dewpoint 4°F An 8-hr period was used to evaluate these changes; that provides time for checking instrumentation and determining the cause of the changes. The 8-hr evaluation period was predicted on determination of the magnitude of small leaks. Large leaks would of course be evaluated much sooner.

6B.2 BASIC DATA USED FOR CALCULATIONS

1. Sphere volume.

2. Sphere environment.

a. Average temperature - 120°F

b. Dewpoint - 70°F

3. Normal containment cooling radioactivity.

a. Radiogas 2.5 counts per sec (7.5 x 10-7 pCilcm 3)

b. Particulate 16 counts per sec (1.6 x 10-3 pCilcm 3 )

4. Normal primary coolant radioactivity after 1 hr.

a. Radiogas activity 5 x 10-3 pCilml H2 0

b. Particulate 5 x 10-2 pCilml H2 0 6B.3 SAMPLE CALCULATIONS

1. Dewpoint in containment cooling system.

a. At 120°F and 70°F dewpoint - the water content of the sphere would be 0.016 Ib of water per pound of dry air

b. At a dewpoint of 74°F the water content of the sphere would be 0.018 Ib of water per pound of dry air let X =the leak rate into the sphere in gallons per hour (0.018 - 0.016) Ib H2 0/ Ib dry air x 1.8 x 106 ft3 x 0.081 x 109 1b / ft3 X = 121 8hrs x 8.31b / gal

  =3.95 gal/hr or 100 gal/day

2. Radioactivity in containment cooling system.

Chapter 6, Page 135 of 170 Revision 20 OAG10000215_0844

IP2 FSAR UPDATE

a. Radiogas activity (1) Increase in activity 1 cps on installed monitor The radiogas activity increase = 3 x 10-7 IlCilcm3 (2) Let Y =leak rate into a sphere in gallons per hour y 3.0xl0- 7 flCi / em3 air x 5.05 x 1010 em 3 air 8hrx5xl0- 3 flCi / ml H20 x 3.8 X 103 ml / gal

    =99.8 gal/hr or 2400 gal/day

b. Particulate activity in containment cooling system 8 counts per sec on the installed monitor Radioactivity increase = 8 x 10-9 I-lCilcm 3 air Let Z = leak rate into the sphere in gallons per hour Z 8 x 1O-9flCi/ em3 air x 5.05 x 1010 em3 air 8hr x 5 x 1O-2flCi/ ml H20x 3.8 x 103 ml/ gal

  =0.265 gal/hr or 6 gal/day Chapter 6, Page 136 of 170 Revision 20 OAG10000215_0845

IP2 FSAR UPDATE APPENDIX6C POSTACCIDENT CONTAINMENT ENVIRONMENT, REVISION 1 TABLE OF CONTENTS Section and Title 6C. Definition of Postaccident Containment Environmental Conditions 6C.1.1 Design-Basis Accident Temperature-Pressure Cycle 6C.1.2 Design-Basis Accident Radiation Environment 6C.1.3 Design Chemical Composition of the Emergency Core Cooling Solution 6C.1.4 Trace Composition of Emergency Core Cooling Solution 6C.2 Materials of Construction in Containment 6C.3 Corrosion of Metals of Construction in Design-Basis Emergency Core Cooling System 6CA Corrosion of Metals of Construction by Trace Containments in Emergency Core Cooling Solution 6C.4.1 Mercury 6CA.2 Chlorine 6CA.2.1 Low Temperature of Emergency Core Cooling Solution 6CA.2.2 Low Chloride Concentration of Emergency Core Cooling Solution 6CA.2.3 Alkaline Nature of the Emergency Core Cooling Solution 6C.S Corrosion of Aluminum Alloys 6C.S.1 Aluminum Corrosion Products in Alkaline Solution 6C.S.2 Behavior of Circulating Aluminum Corrosion Products 6C.6 Compatibility of Protective Coatings with Postaccident Environment 6C.7 Evaluation of the Compatibility of Concrete and Emergency Core Cooling Solution in the Postaccident Environment 6C.8 Miscellaneous Materials of Construction 6C.8.1 Sealants 6C.8.2 Polyvinylchloride Protective Coating 6C.8.3 Fan Cooler Materials 6C.9 Environmental Requalifications References for Appendix 6C Chapter 6, Page 137 of 170 Revision 20 OAG1000021S_0846

IP2 FSAR UPDATE Appendix 6C POSTACCIDENT CONTAINMENT ENVIRONMENT LIST OF TABLES Table No. 6C-1 Review of Sources of Various Elements in Containment and Their Effects on Materials of Construction 6C-2 Materials of Construction in Reactor Containment 6C-3 Inventory of Aluminum in Containment 6C-4 Corrosion of Aluminum Alloys in Alkaline Sodium Borate Solution 6C-5 Corrosion Products of Aluminum Following Design-Basis Accident, Indian Point Unit 2 6C-6 Summary of Unit 2 Aluminum Corrosion Product Solubility Data 6C-7 Concrete Specimen Test Data 6C-8 Evaluation of Sealant Materials for Use in Containment Chapter 6, Page 138 of 170 Revision 20 OAG10000215_0847

IP2 FSAR UPDATE Appendix 6C POSTACCIDENT CONTAINMENT ENVIRONMENT LIST OF FIGURES Figure No. 6C-1 Containment Atmosphere Temperature Design Bases Safety Injection 6C-2 Postaccident Containment Materials Design 6C-3 Postaccident Core Materials Design Conditions 6C-4 Containment Atmosphere Direct Gamma Dose Rate 6C-5 Containment Atmosphere Integrated Gamma Dose Level 6C-6 Titration Curve for Trisodium Phosphate in Boric Acid Solution 6C-7 Temperature-Concentration Relation for Caustic Corrosion of Austenitic Stainless Steel 6C-8 Aluminum Corrosion in Design-Basis-Accident Environment 6C-9 Aluminum Corrosion as a Function of pH 6C-10 Solubility of Aluminum Corrosion Products as a Function of pH 6C-11 Boron Loss From Boron-Concrete Reaction Following a Design-Basis Accident 6C-12 Containment Pressure Transient During Blowdown Phase vs Time Chapter 6, Page 139 of 170 Revision 20 OAG10000215_0848

IP2 FSAR UPDATE Appendix 6C POST ACCIDENT CONTAINMENT ENVIRONMENT 6C.1 DEFINITION OF POSTACCIDENT CONTAINMENT ENVIRONMENTAL CONDITIONS As part of the initial license application, an evaluation of the suitability of materials of construction for use in the reactor containment system was performed considering the following:

1. The integrity of the materials of construction of engineered safeguards equipment when exposed to post-design-basis accident conditions.

2. The effects of corrosion and deterioration products from both engineered safeguards (vital equipment) and other (nonvital) equipment on the integrity and operability of the engineered safeguards equipment.

Reference post-design-basis accident environment conditions of temperature, pressure, radiation, and chemical composition are described in the following sections. The time-temperature-pressure cycle used in the materials evaluation is most conservative, since it considers only partial safeguards operation during the design-basis-accident. The spray and core-cooling solutions considered here include both the design chemical compositions and the fission products, which may conceivably be transferred to the solution during recirculation through the various containment safeguards systems. The original chemistry for the Containment Spray System utilized an alkaline adjusted sodium borate containment spray with the pH adjusted by sodium hydroxide. Use of solid trisodium phosphate for pH control of the solution has been used at a number of plants and was implemented at Indian Point 2 (lP2) in 1997. Reference 24 (WCAP-14542) discusses the benefits and justification for this change. This section was updated to incorporate those changes and much of the updated information was drawn from that WCAP. Updated references were also added as appropriate. 6C.1.1 Design-Basis Accident Temperature-Pressure Cycle Figures 6C-1 and 6C-12 present the temperature-pressure-time relationship following the design-basis accident. These figures represent the containment condition for the following safety feature operation. One of the two spray pumps is considered to inject into the containment. When the refueling water storage tank is empty, the recirculation pumps can supply flow to the spray headers. Recirculation flow through one recirculation pump is cooled in the residual heat exchanger. Figures 6C-2 and 6C-3 present materials evaluation test conditions for the containment and core environment, respectively. Materials evaluations were performed, in general, for conditions either simulating the time-temperature conditions of Figure 6C-2 or conservatively considering higher temperatures for longer periods. The basis for each material evaluation is described with the discussion of its particular suitability. Chapter 6, Page 140 of 170 Revision 20 OAG10000215_0849

IP2 FSAR UPDATE 6C.1.2 Design-Basis Accident Radiation Environment The evaluation of materials for use in containment includes a consideration of the radiation stability requirements for the particular materials application. Figures 6C-4 and 6C-S present the post-design-basis accident containment atmosphere direct gamma dose rate and the integrated direct gamma dose, respectively. These data were calculated on the basis of a core meltdown and assume the following fission product fractional releases, consistent with the TID-14844 model:

1. Noble gases, 1.0

2. Halogens, O.S

3. Other isotopes, 0.01 6C.1.3 Design Chemical Composition Of The Emergency Core-Cooling Solution Nuclear Regulatory Commission Branch Technical Position MTEB 6-1 (ref 31) specifies a minimum pH level of 7.0 of the postaccident emergency coolant water, operation higher in the pH 7.0 to 9.S range for greater assurance that no stress corrosion cracking will occur, and if pH greater than 7.S is used consideration should be given to hydrogen generation from aluminum.

The system designs provide for the use of alkaline-adjusted boric acid solution as the spray and core-cooling fluid. Initially the injection solution is not alkaline-adjusted since the RWST contains only boric acid and not TSP. It is not until re-circulation from the sump, where the injected water has dissolved TSP, that the spray and core-cooling fluid is alkaline adjusted. Plant designs that use the spray solution for retention of fission product iodine in solution, as well as containment cooling, include provisions for addition of chemical additive to the emergency core cooling system. Originally, that additive was a concentrated sodium hydroxide solution but a number of plants have converted to dry trisodium phosphate granules. Boric acid solution, containing approximately 2000 ppm boron, is pumped from the refueling water storage tank to the containment system by means of the safety injection system pumps, residual heat removal pumps, and the spray pumps. Granular trisodium phosphate is stored in baskets strategically located in the post-accident flooded region of the containment. Initially the containment spray will be boric acid solution from the refueling water storage tank which has a pH of approximately 4.S. As the initial spray solution and subsequently the recirculation solution comes in contact with the trisodium phosphate, the TSP dissolves raising the pH of the sump solution to an equilibrium value between 7.0 and 9.S (ref 24, pg 39-40). Titration curves for TSP in Boric acid developed in CN-CDME-00-10 (ref. 32) are shown in figure 6C-6. Based on these curves, 8000 pounds of trisodium phosphate dodecahydrate (Na3P04

12H 2 0) is sufficient to assure a post-LOCA sump pH of 7.0 (ref. CN-CRA-96-00S, Rev. 2) with a margin of approximately 41 % to account for formation of acids over time in the solution. In addition the maximum pH due to trisodium phosphate is 7.61.

Reference 24A addresses the time required to submerge and dissolve the TSP and concludes that conservatively the dissolution times would be 1.7 hours for 6000 of TSP and 2 hours for 8000 pounds. Realistically, the dissolution time would be considerably less. The solutions are considered aerated through the entire exposure period. Chapter 6, Page 141 of 170 Revision 20 OAG1000021S_08S0

IP2 FSAR UPDATE 6C.1.4 Trace Composition Of Emergency Core Cooling Solution During spraying and recirculation, the emergency core cooling solution will wash over virtually all the exposed components and structures in the reactor containment. The emergency core cooling solution is recirculated through a common sump, and hence, any contamination deposited in or leached by the solution from the exposed components and structures will be uniformly mixed in the solution. The materials compatibility discussion includes consideration of the effects of trace elements that are identified as conceivably being present in the emergency core cooling solution during recirculation. To identify the trace elements in the containment that may have a deleterious effect on engineered safeguards equipment, one must first establish, which elements are potentially harmful to the materials of construction of the safeguards equipment, and second, ascertain the presence of these elements in forms, which can be released to the emergency core cooling solution to following a design-basis accident. Table 6C-1 presents a listing of the major periodic groups of elements. Elements that are known to be harmful to various metals are noted and potential sources of these elements are identified. A discussion of the effects of these elements is presented in later sections. 6C.2 MATERIALS OF CONSTRUCTION IN CONTAINMENT All materials in the containment are reviewed from the standpoint of ensuring the integrity of the equipment of which they are constructed and to ensure that deterioration products of some materials do not aggravate the accident condition. In essence, therefore, all materials of construction in the containment must exhibit resistance to the postaccident environment or, at worst, contribute only insignificant quantities of the trace contaminants that have been identified as potentially harmful to vital safeguards equipment. This must be true for these materials in both the new condition and for the aged condition at which the postaccident environment might be more likely to be encountered. In addition to the integrity of major components (e.g. piping, supports, vessels, containment structures, etc.), environmental qualification of Class 1E equipment must not be affected. Section 6C.7 addresses requalification of Class 1E equipment. Table 6C-2 lists typical materials of construction used in the reactor containment system. Examples of equipment containing these materials are included in the table. Corrosion testing, described in Section 6C.3, showed that of all the metals tested only aluminum alloys were found incompatible with the alkaline sodium borate solutions. Aluminum was observed to corrode at a significant rate with the generation of hydrogen gas. Since hydrogen generation can be hazardous to containment integrity, a detailed survey was conducted to identify all aluminum components in the containment. Table 6C-3 lists the nuclear steam supply system aluminum inventory that is present in the reactor containment. Included in the table is the mass of metal and exposed surface area of each component. The 1100 and the 6000 series aluminum alloys are generally the major types found in the containment. This inventory reflects the determination to exclude as much as practicable the actual use of aluminum in the containment. Chapter 6, Page 142 of 170 Revision 20 OAG10000215_0851

IP2 FSAR UPDATE 6C.3 CORROSION OF METALS OF CONSTRUCTION IN DESIGN-BASIS EMERGENCY CORE COOLI NG SOLUTION Emergency core cooling components are primarily austenitic stainless steel and hence are quite corrosion resistant to the alkaline sodium borate solution as demonstrated by corrosion tests performed at Westinghouse and Oak Ridge National Laboratory.1 The general corrosion rate, for type 304 and type 316 stainless steels was found to be 0.01 mils per month in pH 10 solution at 200°F. Data on corrosion rates of these materials in the alkaline sodium borate solution have also been reported by Oak Ridge National Laboratory 2,3 to confirm the low values. Extensive testing was also performed on other metals of construction that are found in the reactor containment. Testing was performed on these materials to ascertain their compatibility with the spray solution at design postaccident conditions and to evaluate the extent of deterioration product formation, if any, from these materials. Metals tested included Zircaloy, Inconel, aluminum alloys, cupro-nickel alloys, carbon steel, galvanized carbon steel, and copper. The results of the corrosion testing of these materials are reported in detail in Reference 1. Of the materials tested, only aluminum was found to be incompatible with the alkaline sodium borate solution. Aluminum corrosion is discussed in Section 6C.5. The following is a summary of the corrosion data obtained on various materials of construction exposed for several weeks in aerated, alkaline (pH 9.3 to 10.0) sodium borate solution at 200°F. The exposure condition is considered conservative since the test temperature (200°F) is considerably higher than the long-term design-basis accident temperature. Maximum Observed Corrosion Rate Material (mil/month) Carbon Steel 0.003 Zircolay-4 0.004 Inconel718 0.003 Copper 0.03 90-10 Cu-Ni 0.002 70-30 Cu-Ni 0.051 Galvanized carbon steel 0.031 Brass -0.01 Tests conducted at Oak Ridge National Laboratory 2,3 have also verified the compatibility of various materials of construction with alkaline sodium borate solution. In tests conducted at 284, 212, and 130°F, stainless steels, Inconel, cupro-nickels, Monel, and Zircaloy-2 experienced negligible changes in appearance and negligible weight loss. Corrosion tests at both Westinghouse and Oak Ridge National Laboratory have shown copper suffers only slight attack when exposed to the alkaline sodium borate solution at design-basis accident conditions. The corrosion rate of copper, for example, in alkaline sodium borate solution at 200°F is approximately 0.03 mils per month. 1 The corrosion of copper in an alkaline sodium borate environment under spray conditions at 284°F and 212°F have been reported by Oak Ridge National Laboratory. Corrosion penetration of less than 0.02 mil was observed after Chapter 6, Page 143 of 170 Revision 20 OAG10000215_0852

IP2 FSAR UPDATE 24-hr exposure at 284°F (see Reference 3, Table 3.13) and a corrosion rate of less than 0.3 mils per month was observed at 212°C (see Reference 2, Table 3.6). It can be seen therefore, that the corrosion of copper in the postaccident environment will have a negligible effect on the integrity of the material. Further, the corrosion product formed during exposure to the solution appears tightly bound to the metal surface and hence will not be released to the emergency core cooling solution. The corrosion rate of galvanized carbon steel in alkaline sodium borate (3000 ppm boron, pH 9.3) is also low. Tests conducted in aerated solutions showed the corrosion rate to be 0.003 mils per month (0.046 mg/dm 2-hr) and 0.002 mils per month (0.036 mg/dm 2-hr) for temperatures of 200 and 150°F, respectively. Therefore, it can be seen that the corrosion of zinc (galvanized) in alkaline borate solution is minimal and will not contribute significantly to the postaccident hydrogen buildup. Consideration was given to possible caustic corrosion of austenitic steels by the alkaline solution. Data presented by Swandby (Figure 6C-7) show that these steels are not subject to caustic stress cracking at the temperature (285°F and below) and caustic concentrations (less than one weight percent) of interest. It can be seen from Figure 6C-7 that the stress cracking boundary minimum temperature as defined by Swandby coincides with a high free caustic concentration (approximately 40-percent) and is considerably above (approximately 80°F) the long-term postaccident design temperature. Further, from Figure 6C-7 a temperature in excess of 500°F is required to produce stress corrosion cracking at a sodium hydroxide concentration greater than 85-percent. 6C.4 CORROSION OF METALS OF CONSTRUCTION BY TRACE CONTAMINANTS IN EMERGENCY CORE COOLING SOLUTION Of the various trace elements that could occur in the emergency core cooling solution in significant quantities, only chlorine (as chloride) and mercury are adjudged potentially harmful to the materials of construction of the safeguards equipment. 6C.4.1 MERCURY The use of mercury or mercury-bearing items, however, is restricted in the containment. This includes mercury vapor lamps, fluorescent lighting, and instruments that employ mercury for pressure and temperature measurements and for electrical equipment. The use of mercury is limited to the refueling cavity lights. Potential sources of mercury therefore, are generally excluded from the containment and hence, no hazard from this element is recognized. The refueling cavity lights contain a small amount of mercury in the arc tube, enclosed in a quartz enclosure to preclude breakage due to thermal shock. An evaluation has demonstrated that neither the arc tube nor the outer quartz protective tube will break during a seismic event and they can withstand both the pressure and temperature expected during a loss-of-coolant accident. 6CA.2 Chlorine The possibility of chloride stress corrosion of austenitic stainless steels has also been considered. It is believed that corrosion by this mechanism will not be significant during the postaccident period for the following reasons. Chapter 6, Page 144 of 170 Revision 20 OAG10000215_0853

IP2 FSAR UPDATE 6CA.2.1 Low Temperature of Emergency Core Cooling Solution The temperature of the emergency core cooling solution is reduced after a relatively short period of time (i.e., a few hours) to about 150°F. While the influence of temperature on stress corrosion cracking of stainless steel has not been unequivocally defined, significant laboratory work and field experience indicate that lowering the temperature of the solution decreases the probability of failure. Hoar and Hines 5 observed this trend with austenitic stainless steel in 42 weight percent solutions of MgCI2 with temperature decrease from 310°F to 272°F. Staehle and Latanision 6 present data that also show the decreasing probability of failure with decreasing solution temperature from about 392°F to 302°F. Staehle and Latanision 6 also report the data of Warren 7 that showed the significant change with decrease in temperature from 212°F to 104°F. The work of Warren, while pertinent to the present consideration in that it shows the general relationship of temperature to time to failure, is not directly applicable in that the chloride concentration (1800 ppm CI) believed to have effected the failure was far in excess of reasonable chloride contamination, which may occur in the emergency core cooling solution. More recent articles by Sedricks (ref 28), Moller (ref 29), and Macdonald & Cragnolino (ref 30) all state the importance of temperature as a variable in determining whether chloride stress corrosion cracking will occur but yet do not provide any definitive guidance. Jiang and Staehle (ref 34) correlate data from 17 references and conclude that for constant stress an Arrhenius form equation is reasonable for presenting the dependencies on tf . 6CA.2.2 Low Chloride Concentration of Emergency Core Cooling Solution It is anticipated that the chloride concentration of the emergency core cooling solution during the post accident period will be low. Throughout plant construction, surveillance is maintained to ensure that the chloride inventory in the containment would be maintained at a minimum. Controls on use of chloride-bearing substances in the containment include the following:

1. Restriction in chloride content of water used in concrete.

2. Prohibition of use of chloride in cleaning agents for stainless steel components and surfaces.

3. Prohibition of use of chloride in concrete etching for surface preparation.

4. Use of non-chloride bearing protective coatings in containment.

5. Restriction in chloride concentration in safety injection solution, 0.15-ppm chloride maximum.

The effect of decreasing chloride concentration on decreasing the probability of failure of stressed austenitic stainless steel has been shown by many experimenters. Staehle and Latanision 6 present data of Staehle that show the decrease in probability of failure with decrease in chloride concentration at 500°F. Edeleanu 8 shows the same trend at chloride concentrations from 40 to 20-percent as MgCb and reported no failures in this experiment at less than about 5-percent MgCI 2. Westinghouse corrosion tests (ref. 22) intended to simulate design basis accident conditions showed that crack initiation time increases with decreasing chloride concentration in tests. Chapter 6, Page 145 of 170 Revision 20 OAG10000215_0854

IP2 FSAR UPDATE Instances of chloride cracking at representative emergency core cooling solution temperatures and at low solution chloride concentration have generally been on surfaces on which concentration of the chloride occurred. In the emergency core cooling system, concentration of chlorides is not anticipated since the solution will operate subcooled with respect to the containment pressure and further, the containment atmosphere will be 100-percent relative humidity. 6CA.2.3 Alkaline Nature of the Emergency Core Cooling Solution The emergency core cooling solution will have a solution pH of greater than 7.0 after dissolution of the trisodium phosphate additive stored in the sumps. Numerous investigators have shown that increasing the solution pH decreases the probability of failure. Thomas et al.,9 showed that the failure probability decreases with increasing pH of boiling solutions of MgCI 2 . More directly applicable, Scharfstein and Brindleio showed that increasing the solution pH to 8.8 by the addition of NaOH prevented the occurrence of chloride stress corrosion cracking in a 10-ppm Chloride (as NaCI) solution at 185°F. Thirty stressed stainless-steel specimens including 304 as received, 347 as received, and 304 sensitized were tested. No failures were observed. Other test runs by Schafstein and Brindley showed the influence of solution pH on higher chloride concentrations, up to 550 ppm Chloride; however, in these tests the pH-adjusting agents were either sodium phosphate or potassium chromate. The authors express the opinion, however, that in the case of the chromate solution, chloride cracking inhibition was simply because the hydrolysis yielded a pH of 8.8 and not because of an influence of the chromate anion. A similar hydrolysis will occur in the borate solution. Studies conducted at Oak Ridge National Laboratory by Griess and Bocarella 11 on type 304 and type 316 stainless-steel U-bend stress specimens exposed to an alkaline borate solution (0.15M NaOH - 0.28M H3 B03 ) containing 100-ppm chloride (as NaCI) showed no evidence of cracking after 1 day at 140°C, 7 days at 100°C, 29 days at 55°C. These extreme test conditions, combined with the fact that some parts of the test specimens were subjected to severe plastic deformation and intergranular attack before exposure, show that the probability of chloride induced stress corrosion cracking in a postaccident environment is very low indeed. Westinghouse corrosion tests (ref. 22) showed that at pH 7, 100 ppm CI, sensitized and non-sensitized samples of 304 stainless steel cracked in approximately 7.5 and 10 months, respectively. Based primarily on those results, Branch Technical Position MTEB 6-1 (ref. 31) recommends that the minimum pH of the sump solution should be 7.0 and that the higher the pH, in the range 7 to 9.5, the greater the assurance that stress corrosion cracking will not occur. As discussed in section 6C.1.3, the initial pH of the solution will be approximately 4 and will increase after the trisodium phosphate dissolves. Therefore, for some period of time, conservatively estimated at 2.0 hours in reference 24, the spray solution will be below 7.0. Westinghouse corrosion tests (ref. 22) indicate that the minimum time to crack (100% crack of a 204 SS welded single U-bend) in a pH 4.5, 100 ppm CI solution is 3 days and no cracking of any test materials was observed before 8 hours. Thus crack initiation occurred between 8 hours and three days. pH adjustment must occur prior to initiation of cracking. Hence, based on these results, it is necessary that the pH of the sump solution be raised above 7.0 within 8 hours Chlorides are not expected to instantaneously appear in the sump solution in concentrations sufficient to initiate cracking. The initial spray and safety injection solution is drawn from the Chapter 6, Page 146 of 170 Revision 20 OAG10000215_0855

IP2 FSAR UPDATE refueling water storage tank where the chloride concentration is limited to 0.15 ppm. The Westinghouse tests indicate that crack initiation in boric acid with 0.4 ppm chloride and pH of approximately 4 requires extended exposure times (12 months in one example). Hence, cracking will not occur during the relatively brief spray and safety injection. During recirculation, as the solution washes over the containment structures and components, chlorides and other contaminants will be removed from the surfaces and dissolved in the solution. Concrete is potentially a significant chloride source but is painted with a nuclear qualified coating which is expected to greatly impede chloride leaching. An extended time period will be required for chloride concentration to build up to critical concentrations (if they ever do). Since the time required to adjust the sump solution pH to greater than 7.0 by dissolution of trisodium phosphate is much less than S hours, pH adjustment will occur well before chloride concentrations have built up to a critical level. In summary, therefore, it is concluded that exposure of the stainless steel engineered safety feature components to the emergency core cooling solution during the postaccident period will not impair its operability from the standpoint of chloride stress corrosion cracking. The environment of low temperature, low chlorides, and high pH that will be experienced during the postaccident period will not be conducive to chloride cracking. 6C.5 CORROSION OF ALUMINUM ALLOYS Corrosion testing has shown that aluminum alloys are not compatible with alkaline borate solution. The alloys generally corrode fairly rapidly at the postaccident condition temperatures with the liberation of hydrogen gas. A number of corrosion tests were conducted in the Westinghouse laboratories (ref. 1, 23) and at Oak Ridge National Laboratory facilities. A review of applicable corrosion data is given in Table 6C-4 and on Figure 6C-S. 6C.5.1 Aluminum Corrosion Products In Alkaline Solution The corrosion of aluminum in alkaline solution expected following a design-basis accident, has been shown to proceed with the formation of aluminum hydroxide 12- 14 and the aluminate ion, as well as with the production of hydrogen gas. The design-basis accident conditions expected for the Indian Point Unit 2 plant include the establishment of an alkaline emergency core cooling solution having a total volume of liquid of 4.4 7 x 105 gal after actuation of the engineered safety features. As mentioned above, aluminum is known to corrode in alkaline solution to give a precipitate of AI(OHh, which in turn can redissolve in an excess of alkali to form a complex aluminate. Van Horn 12 noted that the precipitation of AI(OHh begins about pH 4 and is essentially complete at pH 7. A further increase in pH to about 9 causes dissolution of the hydroxide with the formation of the aluminate. Therefore, it can be seen that the solubility of aluminum corrosion products is a function of the pH of the environment. Consistent with this, the corrosion of aluminum is also strongly dependent on the solution pH, because when the corrosion products are dissolved from the metal surface, corrosion of the base metal can proceed more freely. Chapter 6, Page 147 of 170 Revision 20 OAG10000215_0S56

IP2 FSAR UPDATE Figure 6C-9 presents a plot of aluminum corrosion rate as a function of solution pH. 1 The corrosion rate of aluminum is seen to decrease by a factor of 21 (1/0.048) as the pH decreases from 9.3 to 8.3 and by a factor of 83 (1/0.012) as the pH decreases from 9.3 to 7.0. Therefore, one must consider both corrosion and the dissolution of the corrosion products at specific reference conditions, since the two are directly related. The corrosion reactions that are of interest in the design-basis accident condition here would include the reaction of aluminum in alkaline solution to form aluminum hydroxide, i.e., (6C-1) and dissolution of the hydroxide to form the aluminate, i.e., (6C-2) Knowledge of the solubility product of the aluminum hydroxide in an alkaline solution allows the determination the solubility expected for the hydroxide in the design-basis accident environment. Deltombe and Pourbaix 15 have determined the solubility product of aluminum hydroxide. Using the value of 2.28 x 10-11 for Ksp , as reported by Deltombe and Pourbaix, the following calculation can be made. The solubility of AI (OHh is determined from Equation 6A-2 (6C-3) at pH =9.3 (AIO 2.) = 2.28 x 1~:11 =4.6 x 10- 2 moles/liter (6C-4) 5xlO-Therefore, the solubility of AI(OHh in a pH 9.3 solution at 25°C (7rF) is 4.6 x 10-2 moles per liter or 3.0 x 10-2 Ib/gal. Expressed as aluminum, the solubility at these conditions is 1.05 x 10-2 Ib/gal. The solubility of the aluminum corrosion products in the postaccident environment is a function of both solution pH and temperature. Figure 6C-10 presents plots of the corrosion product solubility, expressed in terms of aluminum versus solution pH for temperatures of 77 and 150°F. The change in solubility with temperature is found using the relationship of the free energy of formation, temperature, and the solubility product. Chapter 6, Page 148 of 170 Revision 20 OAG10000215_0857

IP2 FSAR UPDATE With the data available from Figures 6C-9 and 6C-10 and a knowledge of the reference aluminum corrosion behavior for any specific plant, one can calculate the expected solubility limits for the corrosion reaction. For Indian Point Unit 2, there are 4.47 x 105 gal of emergency core cooling solution after actuation of the safety features. The total amount of aluminum present in the Indian Point Unit 2 containment is given in Table 6C-3. Table 6C-S shows the corrosion of aluminum with time for the original (NaOH additive) design basis pH 9.3 postaccident environment. CN-CRA-96-00S calculates a maximum pH of 7.61 with trisodium phosphate used for solution pH control. Table 6C-6 presents a summary of the applicable solubility and corrosion parameters for various conditions. The table lists the applicable solubility products (Ksp) and solubilities at the various temperatures and solution pH together with the soluble aluminum limit for the Indian Point Unit 2 system at the specific conditions. The last values in the table given the aluminum solubility margin after 100 days of corrosion; that is, the soluble aluminum limit divided by the aluminum corroded. It can be seen that in all cases, including the very conservative low-temperature and low-pH conditions; the emergency core cooling solution is not expected to be saturated with aluminum corrosion products. Furthermore, within the expected design conditions for temperature and pH, the aluminum solubility margin ranges from approximately 20 to 106. The preceding analysis is based on the original design basis with NaOH addition and a pH of 8.S to 10.0 in the solution. Use of trisodium phosphate reduces the long term pH to a minimum of 7.0 and a maximum of 7.61 (ref. 27). Figures 6C-9 and 6C-10 show significant (orders of magnitude) decreases in the corrosion rate and solubility of aluminum when the pH is reduced from the 9.3 range to the low 7 range. This is also shown in reference 23 (WCAP-8776). Thus the corrosion rate of aluminum and the production of hydrogen due to that corrosion can be expected to significantly decrease in the post accident environment due to replacement of the NaOH pH control additive by trisodium phosphate. It is concluded therefore, that the corrosion products of aluminum will be in the soluble form during the postaccident period considered and hence, there is no potential for deposition on flow orifices, spray nozzles, or other equipment. 6C.S.2 Behavior Of Circulating Aluminum Corrosion Products The solubility of aluminum corrosion products has shown that for this plant, the entire inventory produced after 100 days of exposure to the post-design-basis accident condition would remain in solution. The review also indicates that the emergency core cooling solution is only approximately 17-percent saturated at 7rF and less than 1-percent saturated at 1S0°F. However, it is of interest to review the experience of facilities that have operated with insoluble aluminum corrosion products and to relate their conditions with those expected in the postaccident environment. The most significant experience available is that of Griess 16 who operated a recirculating test facility to measure the corrosion resistance of a variety of materials in alkaline sodium borate spray solution. Tests were conducted on 1100, 3003, SOS2, and 6061 aluminum alloys exposed at 100°C in pH 9.3 sodium borate solution (0.1SM NaOH - 0.28M H3B03). It was reported that even though the Chapter 6, Page 149 of 170 Revision 20 OAG1000021S_08S8

IP2 FSAR UPDATE solution contained copious amounts of flocculent aluminum hydroxide, it had no effect on flow through the spray nozzle (0.093-in. orifice). The pH of the solution did not change because of the increase in the corrosion products. Griess 16 in describing his observations regarding aluminum corrosion product deposition potential stated that:

1. No significant deposition was observed on the cooling coil installed in the solution.

2. No significant deposition was observed on the heated surfaces of the facility.

3. No significant deposition was observed on isothermal facility surfaces.

The amounts of aluminum corroded to the solution in the tests conducted by Griess at 55 and 100°C were approximately 4.0 and 18.6 g, respectively. The concentration of aluminum present in the recirculation stream, therefore, was approximately 0.2 and 1 g/liter, respectively. This value is a factor of about 5 above the aluminum concentration expected in the postaccident emergency core cooling solution at Indian Point Unit 2 in a pH 9.3 (NaOH additive) solution after 100 days, and many times that when the lower pH with the trisodium phosphate additive is considered. Hatcher and Rae 17 describe the appearance of turbidity in the NRU reactor and "purpose" that deposition of aluminum corrosion products may have occurred on heat exchanger surfaces, although they do not report any specific examination results. Moreover, Hatcher and Rae report no operations problems associated with the presence of aluminum corrosion product turbidity in the NRU reactor. The overall heat transfer coefficient for each NRU reactor heat exchanger was measured after 2 yr. of full-power operation on several occasions and within the limit of accuracy of the measurements, reported at approximately 5-percent, no change in the thermal resistance had been observed. It is concluded, therefore, both from the work of Griess and Hatcher and Rae, that the deposition of aluminum corrosion products on heat exchangers surfaces will not be significant in the postaccident environments even for the circumstances of insoluble product formation. 6C.6 COMPATIBILITY OF PROTECTIVE COATINGS WITH POSTACCIDENT ENVIRONMENT The investigation of materials compatibility in the postaccident design basis environment also included an evaluation of protective coatings for use in containment. The results of the protective coatings evaluation presented in WCAP-7198 18 , showed that several inorganic zincs, modified phenolics, and epoxy coatings are resistant to an environment of high temperature (320°F maximum test temperature) and alkaline sodium borate. Long-term tests included exposure to spray solution at 150°F to 175°F for 60 days, after initially being subjected to the conservative design-basis accident cycle shown in Figure 6C-3. The protective coatings, which were found to be resistant to the conditions, that is, exhibited no significant loss of adhesion to the substrate nor formation of deterioration products, comprise virtually all of the protective coatings recommended for use in the containment. Hence, the protective coatings will not add deleterious products to the core-cooling solution. It should be pointed out that several test panels of the recommended types of protective coatings were exposed for two design-basis accident cycles and showed no deterioration or loss of adhesion with substrate. Chapter 6, Page 150 of 170 Revision 20 OAG10000215_0859

IP2 FSAR UPDATE In July 1973, Regulatory Guide 1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants", (35) was issued to describe an acceptable method for complying with the NRC's quality assurance requirements with regard to protective coatings applied to ferritic steels, stainless steel, zinc-coated (galvanized) steel, concrete, or masonry surfaces of water-cooled nuclear power plants. Revision 1 of Regulatory Guide 1.54 was issued in 2000. Plants whose design basis that includes a commitment to Regulatory Guide 1.54 require that protective coatings be qualified and capable of surviving a design basis accident without adversely affecting safety related structures, systems, or components needed to mitigate the accident. NCR Generic Letter 98-04 (ref 36) identified the potential for degradation and failure of "qualified" protective coatings applied to exposed surfaces within nuclear power plant containments. The NRC sponsored work at the Savannah River Technology Center to investigate the performance and potential for failure of Service Level 1 coating systems used in nuclear power plant containments (37). The Nuclear Energy Institute has issued "Condition Assessment Guideline: Debris Sources Inside PWR Containments" (38) that provides guidance to PWR operators in assessment of condition of coatings (among other items). 6C.7 EVALUATION OF THE COMPATIBILITY OF CONCRETE AND EMERGENCY CORE COOLING SOLUTION IN THE POST ACCIDENT ENVIRONMENT Concrete specimens were tested in boric acid and alkaline sodium borate solutions at conditions conservatively (320°F maximum and 200°F steady-state) simulating the post design-basis accident environment. The purpose of this study was to establish:

1. The extent of debris formation by solution attack of the concrete surfaces.

2. The extent and rate of boron removal from the emergency core cooling solution through boron-concrete reaction.

Tests were conducted in an atmospheric pressure, reflux apparatus to simulate long-term exposure conditions and in a high-pressure autoclave facility to simulate the design-basis accident short term, high-temperature transient. For these tests the total surface area of concrete in the design containment, which may be exposed to the emergency core cooling solution following a design-basis accident was estimated at 6.3 x 104-ft2. This value includes both coated and uncoated surfaces. The emergency core cooling solution volume for a reference plant was considered at approximately 313,000 gal and the surface to volume ratio from these values is approximately 29 in. 2 /gal. The surface to volume ratios for the concrete-boron tests used were between 28 and 78 in. 2/gal of solution. Table 6C-7 presents a summary of the data obtained from the concrete-boron test series. Testing of uncoated concrete specimens in the postaccident environment showed that attack by both boric acid and the alkaline boric solution is negligible and the amount of deterioration product formation is insignificant. Other specimens covered with modified phenolic and epoxy protective coatings showed no deterioration product formation. These observations are in agreement with Orchard 19 who lists the following resistances of portland cement concrete to attack by various compounds: Cha pter 6, Page 151 of 170 Revision 20 OAG10000215_0860

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1. Boric acid, little or no attack.

2. Alkali hydroxide solution under 10-percent, little or no attack.

3. Sodium borate, mild attack.

4. Sodium hydroxide over 10-percent, very little attack.

Exposure of uncoated concrete to spray solution between 320°F and 210°F has shown a tendency to remove boron very slowly, presumably precipitating an insoluble calcium salt. The rate of change of boron in solution was measured at about 130 ppm per month with pH 9 solution at 210°F for an exposed surface of about 36 in. 2 /gal of solution (much greater than any potential exposure in the containment). The boron loss during the high-temperature transient test (320°F maximum) was about 200 ppm. Figure 6C-11 shows a representation of the boron loss from the emergency core cooling solution versus time by a boron-concrete reaction following a design-basis-accident. The time period from 0 to 6 hr shows the loss during a conservative high-temperature transient test, ambient to 320°F to 285°F. The data from 6 hr to 30 days is base on 210°F data. A depletion of boron at this rate poses no threat to the safety of the reactor because of the large shutdown margin and the feasibility of adding more boron solution should sample analysis show a need for such action. Griess and Bacarella (ref. 21) report on tests of concrete cylinders poured from the actual construction mix at Browns Ferry Nuclear Plant in a simulated post accident environment. None of the cylinders underwent any visible changes and in all cases the strength of the concrete after exposure exceeded the design strength. Solutions in these tests picked up about 10 ppm chloride (leached from the concrete) and the boron concentration was reduced by about 10%. However, the ratio of surface area to solution volume was very high (240 in 2 /gal), about 10 times higher than the ratio calculated above, and the results are therefore substantially greater than would be expected in the actual containment. 6C.8 MISCELLANEOUS MATERIALS OF CONSTRUCTION 6C.8.1 Sealants Candidate sealant materials for use in the reactor containment system were evaluated in simulated design-basis accident environments. Cured samples of various sealants were exposed in alkaline sodium borate solution, pH 10.0, 3000 ppm to a maximum temperature of 320°F. Table 6C-8 presents a summary of the sealant materials tested, together with a description of the panel's appearance after testing. Three generic type of sealants were tested: butyl rubber, silicone, and polyurethane. Each of the materials was the "one package" type, that is, no mixing of components was necessary prior to application. The materials were applied on stainless steel allowed to cure well prior to testing. The test results showed that the silicone sealants tested were chemically resistant to the design-basis accident environment and are acceptable for use in containment. Sealant 780 by Dow Corning Corporation would be acceptable for use in the containment. Major applications of this sealant could be as concrete expansion joint sealant on the liner insulation panels. Sealant 780 will contribute no deterioration products to the emergency core cooling solution during the post design-basis accident period and will maintain its structural integrity and elastic properties. Chapter 6, Page 152 of 170 Revision 20 OAG10000215_0861

IP2 FSAR UPDATE 6C.8.2 Polyvinyl Chloride Protective Coating Tests were conducted to determine the stability of the polyvinyl chloride (PVC) protective coating, of the type, which might be used on conduit in the design-basis accident environment. Samples of the polyvinylchloride exposed to alkaline sodium borate solutions at design-basis accident conditions showed no loss in structural rigidity and no change in weight or appearance. A sample of polyvinylchloride coated aluminum conduit (1-in. 00 x 8-in. long) was irradiated by means of a Co-60 source, at an average dose rate of 3.2 x 106 rads/hr, to a total accumulated dose of 9.1 x 107 rads. The specimen was immersed in alkaline sodium borate solution (pH 10, 3000 ppm boron) at 70°F. Visual examination of the coating after the test showed no evidence of cracking, blistering, or peeling; and the specimen appeared completely unaffected by the gamma exposure. Chemical analysis of the test solution indicated that some bond breakage had occurred in the polyvinyl-chloride coating as evidenced by increase in the chloride concentration. The gamma exposure of approximately 108 rad resulted in a release to the solution of 26 mg of chloride per square foot of exposed polyvinylchloride surface. Considering a total surface area of polyvinylchloride coating present in containment (approximately SOO-ft2) and the emergency core cooling solution volume of 313,000 gal, the chloride concentration increase in the emergency core cooling solution due to irradiation of the coating, would be approximately 0.01 ppm. Therefore, it is concluded that polyvinyl chloride protective coating will be stable in the design basis accident environment. 6C.8.3 Fan Cooler Materials Samples of the following air-handling system materials were exposed in an autoclave facility to the design-basis accident temperature-pressure cycle:

1. Moisture separator pad.

2. High efficiency particulate media.

3. Asbestos separator pads.

4. Adhesive for joining separator pads and high-efficiency particulate air filter media corners.

S. Neoprene gasketing material. The materials were exposed in both the steam phase and liquid phase of a solution of sodium tetraborate (1Sppm boron) to simulate the concentrations expected down stream of the fan-cooler coils. Examination of the specimens after exposure showed the following:

1. Moisture separator pads were somewhat bleached in color but maintained their structural form and showed good resiliency as removed in both liquid and steam phase exposure.

2. High-efficiency particulate filter media maintained its structural integrity in both the liquid and steam phase. No apparent change.

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3. Asbestos separator pads showed some slight color bleaching. However, both steam and liquid phase samples maintained their structural integrity with no significant loss in rigidity.

4. Adhesive material for the HEPA/separator pad edges showed no deterioration or embrittlement and maintained its adhesive property.

5. Neoprene gasketing material is also satisfactory in both the steam and liquid phase.

The material showed only weight gain and a shrinkage of 15 to 30-percent based on a superficial, one flat side area. The gasket thickness decreased about 10-percent. The gasket material was unrestrained during the exposure, and hence the dimensional changes experienced are greater than those which would result as installed in the air-handling side of the fan coolers. 6C.8.4 Polyvinyl Chloride Insulation The containment liner is insulated with a polyvinyl chloride (PVC) insulation enclosed in a stainless steel jacket. Table 14.3-40 lists 6940 ff of 1.25 inch thick PVC insulation enclosed with 0.019 inch jacket and 7434 ff of 1.5 inch thick PVC insulation enclosed with a 0.025 inch jacket. This totals about 1652 fe of PVC installation for this application. Approximately 25 ff of the 1.25 inch thick insulation was replaced with fiberglass insulation. Materials with high chloride content (like PVC) are subject to thermal and/or radiological degradation and are not normally left in containment when a plant returns to power. This insulation material is enclosed in stainless steel jackets which if intact and containing no penetrations should keep the spray solution from contacting the insulation or its degradation products. However, if access paths in the jackets allow sump solution or spray to come in contact with the insulation material, it might be a large source of chlorides. PVC degradation releases HCL which dissolves in water to form hydrochloric acid. Properties of PVC have been reported to change at -1.9 x 107 rads (ref 39) and classified in reference 40 as having excellent resistance to radiation (noticeable changes in properties occur above 107 rads). Reference 40 also indicates that polymers are sensitive only to total radiation dose and not to dose rate so that the dose accumulated to the accident must also be considered. That reference also lists a continuous high temperature limit of 75°C (16rF) for PVC. Degradation of PVC has caused failure of a number of components at nuclear power plants as reported in various NRC reports. 6C.9 ENVIRONMENTAL REQUALIFICATIONS Qualification of electrical equipment for harsh environment is discussed in Section 7.1. The impact of changing the post accident spray solution pH control chemical from sodium hydroxide injected from the spray additive tank to trisodium phosphate allowed to dissolve in the solution collected in the sump on Westinghouse supplied Class 1E equipment was evaluated and documented in WCAP-14495 (ref. 25). Some equipment installed at IP2 was of an older vintage, not qualified in accordance with WCAP-8587 (ref 33), or was provided and/or qualified by a vendor other than Westinghouse and was therefore outside of the scope of the WCAP-14495. A number of additional non-metallic materials, not considered here, contained in the Class 1E electrical equipment are also considered in that evaluation. That evaluation concluded that "spray additive tank elimination will not affect the qualification of Westinghouse Chapter 6, Page 154 of 170 Revision 20 OAG10000215_0863

IP2 FSAR UPDATE supplied Class 1E equipment located inside containment at Indian Point Nuclear Generating Station Unit No.2 (lP2) However, the Notes at the bottom of Table 2.0-1 states that "Evaluation of this equipment is representative of equipment installed at IP2. Additional evaluation will be necessary to affirm applicability/completeness for equipment installed at IP2". REFERENCES FOR APPENDIX 6C

1. M.H. Bell, J.E. Bulkowski, and L. F.pic;one, Investigation of Chemic(3lj.\dditiVE!sfor RE!act()rg()nt(3inlllent$pr(3ys, WCAP-0199 (proprietary), March 1968 ?o(:JWG8PHf1998 (OQOtP[gppi@t§lw},$ppil1f>f?

2. Oak Ridge National Laboratory, ORNL Nuclear Safety Research and Development Program Bimonthly Report for July - August 1968, ORNL-TM-2368, p. 78, 1968.

3. Oak Ridge National Laboratory, ORNL Nuclear Safety Research and Development Program Bimonthly Report for September - October 1968, ORNL-TM-2425, p. 53, 1968.

4. R.K. Swandby, Chemical Engineer Vol. 69, No. 186, November 12, 1962.

5. T.P. Hoar, and J.G. Hines, "Stress Corrosion Cracking of Austenitic Stainless Steel in Aqueous Chloride Solution, "Stress Corrosion Cracking and Embrittlement (ed., W. D.

Robertson), John Wiley and Sons, 1956.

6. R. M. Latanision, and R. W. Staehle, Stress Corrosion Cracking of Iron-Nickel Chromium Alloys, Department of Metallurgical Engineering, The Ohio State University.

7. D. Warren, Proceeding of Fifteenth Annual Industrial Work Conference, Purdue University, May 1960.

8. C. Edeleanu, JISI 173, 1963, 140.

9. K. C. Thomas, et aI., "Stress Corrosion of Type 304 Stainless Steel in Chloride Environment," Corrosion, Vol. 20, 1964, p. 89t.

10. L. R. Sharfstein, and W. F. Brindley, "Chloride Stress Corrosion Cracking of Austenitic Stainless Steel - Effect of Temperature and pH," Corrosion, Vol. 14, 1958, p. 588t.

11. Oak Ridge National Laboratory, ORNL Nuclear Safety Research and Development Program Bimonthly Report for March - April 1969, ORNL-TM-2588, 1969.

12. K. C. Van Horn, Aluminum Volume I, American Society of Metals, 1967.

13. J. Sundararajan, and T. C. Rama Char, Corrosion, Vol. 17, 39t, 1961.

14. F. A. Cotton, and G. Wilkinson, Advanced Inorganic Chemistry, Interscience Publishers, 1962.

15. E. Deltombe, and M. Pourbaix, Corrosion, Vol. 14, 496t, 1958.

16. J. C. Griess, et aI., "Corrosion Studies," p. 76-81, ORNL Nuclear Safety Research and Development Program Bimonthly, July-August, 1968, USAEC Report ORNL-TM-2368.

Chapter 6, Page 155 of 170 Revision 20 OAG10000215_0864

IP2 FSAR UPDATE

17. S. R. Hatcher, and H. K. Rae, Nuclear Sci. and Eng., Vol. 10,316, 1961.

18. L. F. Picone, Evaluation of Protective Coatings for Use in Reactor Containment, WCAP-7198L (proprietary), Westinghouse Electric Corporation, April 1968.

19. D. F. Orchard, "Concrete Technology Volume 1," Contractors Record Limited, London, 1958.

20. Letter from J. D. O'Toole, Con Edison, to S. A. Varga, NRC,

Subject:

Environmental Qualifications Rule, 10 CFR 50.49, dated May 20, 1983. 21 J. C. Griess and A. L. Bacarella, Design Considerations of Reactor Containment Spray Systems - Part III, The Corrosion of Materials in Spray Solutions, ORNL-TM-2412, Part III, December, 1969. 22 D. D. Whyte and L.F. Picone, Behavior of Austenitic Stainless Steel in Post Hypothetical Loss of Coolant Environment, WCAP-7803 (non-proprieatary), December, 1971, WCAP-7798-L (proprietary), November, 1971. 23 R. C. Burchell and D. D. Whyte, Corrosion Study for Determining Hydrogen Generation from Aluminum and Zinc During Post Accident Conditions, WCAP-8776, April 1976. 24 J. L. Grover, J. S. Monahan, and M. C. Rood, Evaluation of the Radiological Consequences from a Loss of Coolant Accident at Indian Point Nuclear Generating Station Unit No.2 Using NUREG-1465 Source Term Methodology, WCAP-14542, July 1996 24A S. M. Ira, Corrections to WCAP-14542 Regarding the Required Mass of Trisodium Phosphate, IPP-02-57, June 2002. 25 B. J. Metro, Spray Additive Tank Deletion Chemistry Impact to Qualification of Westinghouse Supplied Class 1E Equipment, WCAP-14495, July 1996. 26 Nuclear Regulatory Commission Branch Technical Position MTEB 6-1, "pH for Emergency Coolant Water for PWR's". 27 J. L. Grover, IP2 - Determination of TSP Requirements, CN-CRA-96-005, Revision 2, 2003. 28 A. John Sedriks, Stess Corrosion Cracking of Stainless Steels, "Stress Corrosion Cracking", edited by Russel H. Jones, ASM International, 1992. 29 George E. Moller, Designing with Stainless Steels for Service in Stress Corrosion Environments, "Materials Performance", May 1977 pg 23-44 and reprinted in "Corrosion Source Book", American Society for Metals and National Association of Corrosion Engineers, 1984. 30 Digby D. Macdonald and Gustavo A. Cragnolino, Corrosion of Steam Cycle Materials, Chapter 9 of "The ASME Handbook on Water Technology for Power Reactors", Paul Cohen editor-in-chief, 1989. Chapter 6, Page 156 of 170 Revision 20 OAG10000215_0865

IP2 FSAR UPDATE 31 NRC Branch Technical Position MTEB 6-1, pH of Emergency Coolant Water for PWRs, Draft Rev. 2, April, 1996. 32 W. M. Connor, Boric Acid Trisodium Phosphate Titration Curves, CN-CDME-00-10, May, 2000. 33 WCAP-8587, Methodology for Qualifying Westinghouse WRD Supplied NSSS Safety Related Electrical Equipment. 34 X.C. Jiang and R. W. Staehle, Effects of Stress and Temperature on Stress Corrosion Cracking of Austenitic Stainless Steels in Concentrated Magnesium Chloride Solutions, Corrosion, June 1997. 35 NRC Regulatory Guide 1.54, Quality Assurance Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants, Revision 0 -July 1973, Revision 1 - July 2000. 36 NRC Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System and the Containment Spray System After a Loss-of-Coolant Accident Because of Construction and Protective Coating Deficiencies and Foreign Material in Containment, July 1998. 37 M. E. DuPont, et. al. Degradation and Failure Characteristics of NPP Containment Protective Coating Systems Interim Report, WSRC-TR-2000-00079, March 2000. 38 Condition Assessment Guidelines: Debris Sources Inside PWR Containments, NEI 02-01, Revision 1, September 2002. 39 J. Bartko and J. M. Hicks, Radiation Hardness of Non-Metallic Materials Used in the RID 241 and 252 Instrument Lines, Westinghouse R&D Memo No. 77-1C6-QUAEQ-M5, July 1977. 40 J. S. Nimitz, R. E. Allred, and B. W. Gordon, Chemical Compatibility Testing Final Report Including Test Plans and Procedures, SAND2001-1988, May 1994. TABLE 6C-1 (Sheet 1 of 2) Review of Sources of Various Elements in Containment and Their Effects on Materials of Construction Representative Elements Corrosivity of Elements Sources of Elements o He, Ne, Kr, Xe No effect on any materials Fission product release construction Da Li, Na, K Generally corrosion Li - coolant pH-adjusting inhibitive properties for agent steels and copper alloys - Na - spray additive solution, harmful to aluminum concrete leach product Chapter 6, Page 157 of 170 Revision 20 OAG10000215_0866

IP2 FSAR UPDATE K - concrete leach product OOa Mg, Ca, Sr, Sa Generally not harmful to Concrete leach products - steel or copper base alloys deteriorated insulation OOOa Y, La, Ac Not considered harmful in Fission product release low concentrations oVa Ti, Zr, Hf Not considered harmful to Fuel rod cladding, control any materials rod material, alloying constituent Va V, Nb,Ta Not considered harmful to Alloying constituents in low any materials concentration Voa Cr, Mo, W Not considered harmful to Alloying constituents in any materials equipment Vooa Mn, Tc, Re Not considered harmful Mn - alloy constituent Chapter 6, Page 158 of 170 Revision 20 OAG10000215_0867

IP2 FSAR UPDATE TABLE 6C-1 (Sheet 2 of 2) Review of Sources of Various Elements in Containment and Their Effects on Materials of Construction Group Representative Corrosivity of Elements Sources of Elements Elements Vooo Fe, Ni, Cr, Os Fe, Ni, Cr - not harmful to Fe, Ni, Cr - alloying any materials constituents. Others have no identifiable sources ob Cu, Ag, Au Not harmful to any materials Cu present as material of construction and alloying constituent oob Zn,Cd, Hg Hg - harmful to stainless Hg has been entirely steel, Cu alloys, excluded from use in the aluminum containment; Cd finish Zn - unknown plating on components. Zn Cd - unknown galvanizing and alloying constituent ooob B, AI, Ga, In Not harmful to material B - neutron poison additive AI - materials of construction oVb C, Si, Sn, Pb C, Si, Sn not harmful to Si - concrete leach product materials Pb- alloy constituent in Pb considered harmful to some brazes nickel alloys Vb N, P, As, Sb, Bi No effect from N unless N - containment air;Others ammonia is formed; others not identified in unknown significant materials Group Representative Corrosivity of Elements Sources of Elements Elements Vlb O,S,Se, Te S possibly harmful to nickel Te - fission product alloys S - oils, greases, insulating materials Voob F, CI, Br, I F considered potentially CI - concrete leach product, harmful to Zircaloy general contamination CI potentially harmful to F - organic materials stainless steel I and Br - fission products, Br and I not generally low concentration harmful Chapter 6, Page 159 of 170 Revision 20 OAG10000215_0868

IP2 FSAR UPDATE TABLE 6C-2 Materials of Construction in Reactor Containment Material Equipment Application 300 series stainless steel Reactor coolant system, residual heat removal loop, spray system 400 series stainless steel Valve materials Inconel (600, 718) Steam generator tubing, reactor vessel nozzles, core supports, and fuel rod grids Galvanized steel Ventilation duct work, CRDM shroud material, I and C conduit Aluminum Nuclear detectors, I and C equipment, CRDM connectors, paints Copper Service water piping, fan cooler material 70-30 Cu Ni Fan cooler material 90-10 Cu Ni Fan cooler material Carbon steel Component cooling loop, structural steel, main steam piping, etc. Monel Possibly instrument housings Brass Possibly instrument housings Polyvi nylchl ori de Conduit sheathing, electrical insulation, containment liner insulation Protective coatings General use on carbon steel structures and equipment, concrete Inorganic zincs Epoxy Modified phenolics Silicones - neoprene Ventilation duct work gasketing, sealants Chapter 6, Page 160 of 170 Revision 20 OAG10000215_0869

IP2 FSAR UPDATE TABLE 6C-3 Inventory of Aluminum in Containment Item Mass (lb) Surface Area (fe)

1. CRDM connectors 122 42

2. Reactor vessel 269 Very high insulation foil

3. Area monitors 6 4

4. Source, intermediate, 140 40 and power range detectors

5. Process 420 84 instrumentation and control

6. Lighting fixtures and 1061 380 equipment

7. Paint on steam 140 Very high generator, pressurizer and reactor vessel

8. Contingency 250 85 Chapter 6, Page 161 of 170 Revision 20 OAG10000215_0870

IP2 FSAR UPDATE TABLE 6C-4 Corrosion of Aluminum Alloys in Alkaline Sodium Borate Solution Corrosion Data Temperature Alloy Test Rate Exposure Point

        .tEl         lYJ2§    Duration    mg/dm2/h     J2!:i Condition     Reference r

1 275 5053 3 hr 96.2 9 Solution WCAP-7153, Table 9 2 275 5005 3 hr 840 9 Solution WCAP-7153, Table 9 3 200 6061 320 hr 15.4 9.3 Solution WCAP-7153, Table 8 WCAP-7153, Figure 9 4 210 5052 7 days 53.0 9 Solution WCAP-7153, Table 7 WCAP-7153, Figure 8 5 210 5052 2 days 14.0 9 Solution WCAP-7153, Table 5 6 210 5005 2 days 27.1 9 Solution WCAP-7153, Table 5 7 284 5052 1 day 54 9.3 Spray ORNL-TM-2425 Table 3.13 8 284 5052 1 day 31.5 9.3 Solution ORNL-TM-2425 Table 3.13 9 212 6061 3 days 126 9.3 Spray ORNL-TM-2368 Table 3.6 10 212 6061 3 days 110 9.3 Solution ORNL-TM-2368, Table 3.6 11 150 6061 7 days 2.9 9.3 Solution Westinghouse data 12 150 5052 7 days 4.2 9.3 Solution Westinghouse data Chapter 6, Page 162 of 170 Revision 20 OAG10000215_0871

IP2 FSAR UPDATE TABLE 6C-5 Corrosion Products of Aluminum Following Design Basis Accident, Indian Point Unit 2 Mass of Mass of Time After Aluminum Hydrogen AI (OHh Reactor Trip Corroded Produced Formed

  ~                    (lb x 10-2)              (SCF x 10-3 )       (lb x 10-2) 1                      1.71                      3.41               4.94 5                      4.31                      8.60               12.4 10                     4.50                      8.98               13.0 20                     4.88                      9.75               14.1 30                     5.26                      10.5               15.2 40                     5.66                      11.3               16.4 50                     6.06                      12.1               17.5 60                     6.41                      12.8               18.5 70                     6.81                      13.6               19.7 80                     7.21                      14.4               20.9 90                     7.61                      15.2               22.0 100                    7.97                      15.9               23.0 Chapter 6, Page 163 of 170 Revision 20 OAG10000215_0872

IP2 FSAR UPDATE TABLE 6C-6 Summary of Unit 2 Aluminum Corrosion Product Solubility Data Solution Temperature 7rF 150°F Parameter pH 9.3 pH 8.3 pH 9.3 pH 8.3 Solubility product 2.28 x 10-11 2.28 X 10-11 4.16x10- 1O 4.16 X 10-10 KSp Aluminum 1.05 X 10-2 1.05 X 10-3 1.9x10-1 1.9 X 10-2 solubility, Ib AI/gal Soluble aluminum 4.69 X 103 4.69 X 102 8.49 x 104 8.49 X 103 Limit1 for emergency core cooling system, Ib Aluminum (Not used) (Not used) 1 0.048 corrosion rate (normalized) Aluminum (Not used) (Not used) 795 corroded after 100 days, Ib Aluminum 106 19 solubility margin at 100 days

1. Indian Point Unit 2 solution volume 4.48 x 105 gal.

2. Value assumes rapid corrosion of all aluminum paint and reactor vessel foil insulation.

3. Note corrosion rate at 150°F was used for "aluminum corroded" value; hence, value is very conservative.

Chapter 6, Page 164 of 170 Revision 20 OAG10000215_0873

IP2 FSAR UPDATE TABLE 6C-7 Concrete Specimen Test Data Concrete Total Surface/ Exposed Initial Boron Exposure Volume Weight Specimen Test No. Period (in. 2/gal) Change Weight (Days) (Grams) (Grams) Visual Examination 1 24 28 -22.4 560.0 No apparent change 3 28 20 +21.5 404.0 Light, yellowish, deposition specimen 41 72 38 0 641.2 No apparent change

                                                                     - coating adhesion excellent 5               72             43              -0.2   769.5    Light, hard deposit on specimen 6                -42            54                     601.4    No apparent change
                                                                     - small amount of sand particles in test can 7               175            23             +11.0   457.0    No apparent change 81               175            38             +26.5   751.0    No apparent change
                                                                     - coating adhesion excellent 91               -52            78             +4.0    702.0    No apparent change
                                                                     - coating adhesion excellent

1. These specimens coated with Phenoline 305. All others were uncoated.

2. These tests were at high-temperature design-basis accident transient conditions. All others at 195°F - 205°F.

Chapter 6, Page 165 of 170 Revision 20 OAG10000215_0874

IP2 FSAR UPDATE TABLE 6C-8 Evaluation of Sealant Materials For Use In Containment Sealant Type Manufacturer Posttest Appearance Butyl rubber A Unchanged, flexible. Silicone B Unchanged, flexible. Silicone B Unchanged, flexible Polyurethane C Sealant bubbled and became very soft; solution permeated into bubbles. Polyurethane C Sealant swelled and became soft; solution permeated into material. Polyurethane C Sealant swelled and became very soft and tacky; solution permeated into material. 6C FIGURES Figure No. Title Figure 6C-1 Containment Atmosphere Temperature Design Bases Safety Injection Figure 6C-2 Indian Point Unit 2 Postaccident Containment Materials Design Figure 6C-3 Postaccident Core Materials Design Conditions Figure 6C-4 Indian Point Unit 2 Containment Atmosphere Direct Gamma Dose Rate Figure 6C-5 Indian Point Unit 2 Containment Atmosphere Integrated Gamma Dose Level Figure 6C-6 Titration Curve for TSP in Boric Acid Solution Figure 6C-7 Temperature-Concentration Relation For Caustic Corrosion Of Austenitic Stainless Steel Figure 6C-8 Aluminum Corrosion In Design-Basis-Accident Environment Figure 6C-9 Aluminum Corrosion As A Function Of pH Figure 6C-10 Solubility Of Aluminum Corrosion Products As A Function Of pH At 77°F And 150°F Figure 6C-11 Boron Loss From Boron-Concrete Reaction Following A Design-Basis Accident Figure 6C-12 Containment Pressure Transient During Blowdown Phase Vs. Time Chapter 6, Page 166 of 170 Revision 20 OAG10000215_0875

IP2 FSAR UPDATE APPENDIX 60 SPRAY SYSTEM MATERIALS COMPATIBILITY FOR LONG-TERM STORAGE OF SODI UM HYDROXI DE (RETAINED FOR HISTROICAL PURPOSES) SPRAY SYSTEM MATERIALS-COMPATIBILITY FOR LONG-TERM STORAGE OF SODIUM HYDROXIDE TABLE OF CONTENTS Section and Title Reference for Appendix 6D 6D-3 Additional References for Appendix 60 6D-4 LIST OF TABLES TABLE and No. 60-1 Exposure Conditions 6D-5 60-2 Component Materials 6D-6 60-3 Corrosion Rates 6D-7 LIST OF FIGURES Figure and No. 60-1 Temperature - Concentration Relations for Caustic Corrosion of Austenitic Stainless Steel 60-2 Effect of Carbon Dioxide on Corrosion of Iron in NaOH Solution Chapter 6, Page 167 of 170 Revision 20 OAG10000215_0876

IP2 FSAR UPDATE Appendix 60 SPRAY MATERIALS COMPATIBILITY FOR LONG-TERM STORAGE OF SODIUM HYDROXIDE [Historical Information] A materials compatibility review for the spray additive tank and associated equipment during long-term storage of sodium hydroxide is presented below, The exposure conditions are shown in Table 60-1, and the materials for the various components are shown in Table 60-2, The corrosion rates for the various materials at or near the long-term exposure conditions with air contamination are shown on Table 60-3, The immunity of most of the materials in Table 6-2 to caustic cracking at the exposure conditions listed in Table 60-1 has been reported by Logan 1 (see Figure 60-1). No caustic cracking of 17-4 pH or Stellite has been reported? The effect of carbon dioxide from air exposure on the corrosion of iron is shown in Figure 60-2.3 At pH 14, no additional corrosion is observed over that observed in carbon-dioxide-free solution. In the Indian Point Unit 2 system, a nitrogen blanket is continuously maintained over the sodium hydroxide solution in the spray additive tank, thus essentially eliminating any carbon dioxide contamination of the solution. The Norder rubber diaphragm material used in the tank valves was exposed in 33 wt percent sodium hydroxide solution at 110°F for 6 months and found to be unaffected by the simulated spray additive tank solution. The integrity of the structural materials in the spray additive tank system would not be adversely affected even using the corrosion rate presented in Table 60-3 where air contamination is present. In the Indian Point Unit 2 system, where nitrogen blanketing of the spray additive tank would prevent air contamination, the corrosion rates would be even lower with even less effect on the material integrity. Diamond Shamrock Companl reported that no galling of steel valves occurred after exposure to 50-percent sodium hydroxide at 120° to 140°F for greater than 3 years. Stainless steel valves, exhibiting lower corrosion rates, would have an even lower propensity toward galling than steel. Therefore, no galling should occur on the valves exposed to the long-term storage conditions. The total corrosion product released to the spray additive tank as oxide would be less than 1000 g/yr with aerated solution and would be much less with the air-free solution (i.e., the Indian Point Unit 2 solution). This small quantity of corrosion product should not present any problems with clogging of delivery lines. No sodium hydroxide precipitation will occur for a 30 wt percent solution if the temperature of the tank and liners is maintained above 35°F. Since this system is located in an area of the auxiliary building, which is continuously heated to maintain a 50°F minimum temperature, no solid sodium hydroxide would be present and, therefore, no clogging of the lines could occur.

Nordel is a product of E.1. Du Pont de Nemours and Company.

Chapter 6, Page 168 of 170 Revision 20 OAG10000215_0877

IP2 FSAR UPDATE REFERENCES FOR APPENDIX 60

1. H. L. Logan, The Stress Corrosion of Metals, John Wiley and Sons, Inc., NY., "304 and 316 Stainless Steel, "p.138, "410 Stainless Steel," p. 101, "A-516 GR-70," p. 44.

2. Letter from R.R. Gaugh, Armco Steel, to D. D. Whyte,

Subject:

Data from an Armco Internal Report, dated September 26, 1996.

3. F. N. Speller, Corrosion Causes and Prevention, McGraw Hill Book Company, Inc., New York, 1951, p. 195.

4. Personal communication with Robert Sheppard, Assistant Plant Manager, Divisional Technical Center of Diamond Shamrock Company, Painsville, Ohio.

ADDITIONAL REFERENCES FOR APPENDIX 60

1. American Society for Metals, Metals Handbook 8th Edition, Vol. 1! Properties and Selection of Metals, P.670.

2. V.R. Evans, The Corrosion and Oxidation of Metals, Edward Arnold Publishers, Ltd.,

London, 1960,p.454.

3. Huntington Alloy Products Division of International Nickle Company, Inc., Resistance of Huntington Alloy to Corrosion, p.28.

4. J. P. Polar, A Guide to Corrosion Resistance (Climax Molybdenum).

5. Shell Development Company, Corrosion Data Survey, 1960 Edition.

6. Westinghouse Electric Corporation, From unreported work performed at Westinghouse Electric Corporation, NES laboratories.

TABLE 60-1 Exposure Conditions Temperature, OF 110 Nitrogen overpressure Slight positive pressure Sodium hydroxide concentration, wlo 30 Oxygen concentration, normal Nitrogen blanketed Carbon dioxide concentration, normal Nitrogen blanketed Chapter 6, Page 169 of 170 Revision 20 OAG10000215_0878

IP2 FSAR UPDATE TABLE 60-2 Component Materials Spray additive tank 304 stainless steel cladding on steel A-516 GR-70 Piping 304 stainless steel Valve bodies 304 and 316 stainless steel Valve seats Austenitic stainless steel or Stellite Valve stems 17-4 pH and 410 stainless steel Valve diaphragm Ethylene-propylene dipolymer (Nordel rubber by DuPont) TABLE 60-3 Corrosion Rates NaOH Corrosion Temperature Concentration Rates Reference Material m iPmIll Aeration (mils/yr) No. 304 SIS 136 22 to 50 Yes <0.1 1 316 SIS 125 30 Yes <2 2 Steel 179 30 to 50 Yes <20 2 410 SIS 125 30 Yes <2 2 17-4 pH 176 30 Yes 3 to 6 7 SteIi ite 150 50 Yes <0.6 4 Nordel rubber 110 33 Yes <0.004 5 60 FIGURES Figure No. Title Figure 60-1 Temperature - Concentration Relations for Caustic Corrosion of Austenitic Stainless Steel Figure 60-2 Effect of Carbon Dioxide on Corrosion of Iron In NaOH Solution Cha pter 6, Page 170 of 170 Revision 20 OAG10000215_0879

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IP2 FSAR UPDATE CHAPTER 7 INSTRUMENTATION AND CONTROL 7.1 GENERAL DESIGN CRITERIA Complete supervision of both the nuclear and turbine-generator sections of the plant is accomplished by the instrumentation and control systems from the control room. The instrumentation and control systems are designed to permit periodic online tests to demonstrate the operability of the reactor protection system. Criteria applying in common to all instrumentation and control systems are given in the following listing. Thereafter, criteria that are specific to one of the instrumentation and control systems are discussed in the appropriate portion of the description of that system. 7.1.1 Instrumentation and Control Systems Criteria Criterion: Instrumentation and controls shall be provided as required to monitor and maintain within prescribed operating ranges essential reactor facility operating variables. (GDC 12) Instrumentation and controls essential to avoid undue risk to the health and safety of the public are provided to monitor and maintain neutron flux, primary coolant pressure, flow rate, temperature, and control rod positions within prescribed operating ranges. Westinghouse designed and procured all systems that actuate reactor trip and safety feature actions for Indian Point Unit 2. The design of protective grade instrumentation and logic systems are in accordance with the proposed IEEE criteria for nuclear power plant protection system (lEEE-279 Code), dated August 28, 1968. The functional design is originated at Westinghouse with equipment procurement through vendor supplies. Equipment compatibility and integration of component hardware was factored into the design by Westinghouse or under the direct supervision of Westinghouse. The non-nuclear regulating process and containment instrumentation measures temperatures, pressure, flow, and levels in the reactor coolant system, steam systems, containment, and other auxiliary systems. Process variables required on a continuous basis for the startup, power operation, and shutdown of the plant are controlled from and indicated or recorded in the control room. The quantity and types of process instrumentation provided ensure the safe and orderly operation of all systems and processes over the full operating range of the plant. 7.1.2 Related Criteria The following criteria are related to all instrumentation and control systems but are more specific to other plant features or systems, and therefore are discussed in other sections, as listed. Name Discussion Suppression of power oscillations (GDC 7) Chapter 3 Reactor core design (GDC 6) Chapter 3 Quality standards (GDC 1) Chapter 4 Performance standards (GDC 2) Chapter 4 Chapter 7, Page 1 of 109 Revision 20, 2006 OAG10000215_0913
IP2 FSAR UPDATE Fire protection (GDC 3) Chapters 5 and 9 Missile protection (GDC 40) Chapters 4, 5, and 6 Emergency power (GDC 39) Chapter 8 7.1.3 Environmental Qualifications - Original Plant Operations As part of the original plant design for Indian Point Unit 2, environmental requirements were established for all safety-related electrical equipment in the facility. These requirements included environmental conditions, testing, and qualifications as discussed in this section. For a discussion of equipment requalification in accordance with recent NRC guidelines, see Section 7.1.4. Table 7.1-1 lists the equipment located within the primary containment (reactor containment building), which is required to be operable during or following a loss-of-coolant or a steam line break accident. In addition, Table 7.1-1 lists the equipment operational and environmental testing requirements as established as part of the original facility operations. Figures 7.1-1 and 7.1-2 present the environmental conditions of pressure and temperature, respectively, for both the Table 7.1-1 required equipment test conditions and for the containment post loss-of-coolant design accident (LOCA) conditions. Figures 7.1-3 and 7.1-4 present the maximum calculated instantaneous and integrated radiation dose levels inside the containment as a function of time following a TID-14844 model LOCA. 7.1.3.1 Category 1 - Instrumentation Except for sump level channels LT-938, 939, 940, and 941, the supplier completed preliminary qualification tests on pressure and differential pressure transmitters. These are reported in WCAP-7354-L,2 which has been superceded by WCAP-7410-L. 3 Additional instrumentation tests were performed by Westinghouse on equipment obtained from the Indian Point Unit 2 plant equipment supplier. The results of these tests confirmed that the equipment would provide the required signals in the post-LOCA environment. The test conditions of the Westinghouse test were as follows: steam environment, a 5-sec period rise to 286°F and 60-psig pressure and the maintenance of these conditions for 2 hr. All equipment, listed below, continued to operate throughout the test and are typical of transmitter ranges used in the containment. Static Pressure Differential Pressure Transmitters Transmitters 0-2500 psig 0-240-in. of water 1700-2500 psig 0-300 psid Containment sump and recirculation sump level channels consist of hermetically sealed magnetic switches in a stainless steel housing. The instrumentation was designed for submerged service in borated water at 295°F at a pressure of 69 psig. Since instruments of this design have seen considerable actual service in applications more severe than the post-LOCA design conditions, environmental testing for these instruments was not required. Chapter 7, Page 2 of 109 Revision 20, 2006 OAG10000215_0914
IP2 FSAR UPDATE 7.1.3.2 Category 2 - Valves The Indian Point Unit 2 valve operator supplier conducted loss-of-coolant environmental tests on a motor operated valve with a Class H unit similar to those used in this plant. Reports of results indicated that the unit operated satisfactorily at test conditions more severe than those expected in the Indian Point Unit 2 loss-of-coolant or steam break accident environment. In addition, Westinghouse performed environmental tests on a unit similar to that being used in the Indian Point Unit 2 plant. The results of the Westinghouse tests indicated that the equipment would perform its required function in the post-LOCA environment. Tests performed on motor operated valve operators, both Class H and Class B, included the following:
1. Preliminary heat tests (dry heat for 16 hr at 375°F) on limit and torque switches.
All parts operated freely.
2. Preliminary heat tests on actuator. A complete operator assembled and baked at 325 F for 12 hr. Unit operated every 0.5 hr for 2 min, full open to full close. All 0
operations were satisfactory.
3. Preliminary live steam test. Live steam injected into switch compartment. Unit operated every 0.5 hr for 2 min over a period of 9 hr. All operations were satisfactory .

4. Heat aging of motor. Heat aging at 180°C for 100 hr (equivalent to 40-year life) was performed. Comparison of insulation resistance between new and aged motor indicated no significant insulation degradation.

5. Life cycle test. 150 life cycle test under loaded conditions (valve operator produced - 16,500 Ib of thrust). No noticeable change in operator following test.

6. Environmental test. Valve operators subjected to environmental conditions shown in Figures 7.1-1 and 7.1-2 and sprayed continuously for a period of 3 hr with a solution of boric acid and sodium hydroxide.
Results of the tests are as follows:
1. Class H operator (actual peak test conditions 320°F at 90 psig): operator survived 1st day of exposure during which 12 complete reversing cycles were accomplished. Following 1-week exposure to 247°F and 14.7 psig, the unit was operated for two complete reversing cycles. The unit operated satisfactorily.

2. Class B operator: operator survived the 1st day of exposure with 12 complete reversing cycles, However, after 5 days of exposure, the operator failed (failure found to be a short in the motor winding).
As a result of the above tests, Class H operators were supplied where long-term operation is required. Class B operators were supplied where short-term (less than 12 hr) operation is required. Chapter 7, Page 3 of 109 Revision 20, 2006 OAG10000215_0915
IP2 FSAR UPDATE A production line valve motor was irradiated to a level of 2 x 108 rads using a cobalt-60 irradiation source. The irradiated motor and an identical unirradiated motor underwent a series of reversing tests at room temperature, followed by a series of reversing tests at 275°F. The room temperature test was repeated while vibrating the motors at a frequency of 30 cycles per sec. Both motors operated satisfactorily during all of the tests. No significant difference was evident in the comparison of the data for the two units throughout the test period. 7.1.3.3 [R§I§t~~] 7.1.3.3.2 Hydrogen Recombiner System The original flame recombiner system has been replaced with a Passive Autocatalytic Recombiner System (PARS). Qualification testing of the PARS is discussed in Section 6.8.4.1. 7.1.3.3.3 Cable and Splice Tests Cabling of the type that is installed in the Indian Point Unit 2 plant was tested under simulated loss-of-coolant accident conditions. The tests were conducted by the cable manufacturer and Westinghouse and consisted of the following:
1. A test was performed by the cable manufacturer in a steam environment of 214°F for 436 hr. During this test, some cable was energized and was carrying current. A visual inspection following this test showed the cables to be in excellent condition. High voltage, tensile elongation, and stretch showed insignificant changes in their characteristics.

2. A test was performed by the cable manufacturer where the specimens were exposed to a gamma radiation field of 2.8 x 107 rads followed by exposure in a steam atmosphere of 85 psig for two 30-min cycles. Following these tests, the physical appearance of the cables was excellent. Changes in electrical characteristics were as follows:

a. Insulation resistance percent of original value.

b. Specific inductance (SIC) - No change.

c. Dissipation factor - Change from 2.2 to 2.1-percent.

d. AC breakdown percent of original value.
These percentages represent an average of seven samples. Westinghouse performed cable testing in a postaccident steam and chemical environment of 80 psig (maximum) and a temperature in excess of 300 F. The durations of these tests were in 0 excess of 200 hr in the postaccident steam and chemical environment, 68 hr of which was at a steam pressure higher than containment design pressure. The general appearance of the cables following these tests was good. Some loosening of the jacket from the insulation at the cable ends occurred, generally believed to be due to the rapid decrease in pressure during the tests. Had the cable ends been properly made up, this separation could have been prevented. Chapter 7, Page 4 of 109 Revision 20, 2006 OAG10000215_0916
IP2 FSAR UPDATE Westinghouse performed additional testing on 18 cable and cable splice test specimens. The testing consisted of the following:
1. Thermal aging to an equivalent of 40 years of operation. (Kerite cable - 150°C for 192 hr; silicone cable - 210°C for 30 days.)

2. Irradiation to levels up to 2 x 108 rads.

3. Exposing the cables for three weeks to the environmental test conditions shown in Figures 7.1-1 and 7.1-2.

4. Applying a potential of 480-V (with respect to ground) to the cables and conducting rated current through the cables on a daily schedule of 8 hr on and 16 hr off.
Before the admission of steam to the test chamber, it was found that four of the test specimens had open conductors. These four specimens were removed from the chamber, and subsequent examination indicated that the conductors had not been crimped properly. Of the 14 specimens tested in the environment, 13 survived. The 14th was found to have shorted against the test grounding pipe surrounding the cable. The short appeared to have occurred because of the whipping of the cable caused by the steam injection against the cable. According to the above test results, the safeguards cable and splices used on the Indian Point Unit 2 plant will maintain their required integrity under post-LOCA conditions. 7.1.3.4 Postaccident Equipment Radiation Exposure The design basis for the reactor protection system and engineered safety feature equipment radiation exposure is that the equipment must function after exposure associated with the TID-14844 model accident. The maximum anticipated exposure for components located within the containment was originally specified as 1.6 x 108 rads, which is accumulated during 1 year following the accident (note that the integrated exposure for safeguards equipment during 40 years of operation is less than 5 x 105 rads). In the determination of exposure no credit was taken for containment cleanup or other removal mechanism other than isotope decay. The expected integrated exposure on the outside of the containment building, again assuming TID-14844 releases and no credit for cleanup, was originally specified to be less than 102 rads integrated over a year at the containment outside surface. These radiation exposure values are updated and are maintained by the ongoing Environmental Qualification Program described in Section 7.1.4. To establish the combined effect of long-term operation followed by exposure to accident conditions inside the containment, selected components were subjected to thermal aging followed by irradiation. In addition, components were first irradiated and then subjected to thermal aging. Results of the tests indicated that the components would perform satisfactorily following a design-basis accident. Indian Point Unit 2 cables were tested using the same approach as described above, that is, first irradiation, and then thermal aging followed by steam exposure. During exposure to steam the cables carried nominal voltage and current. Chapter 7, Page 5 of 109 Revision 20, 2006 OAG10000215_0917
IP2 FSAR UPDATE 7.1.4 Environmental Qualifications An ongoing program of evaluating the environmental qualification of safety-related electrical equipment at the Indian Point Unit 2 facility has been in progress since early 1980. On May 23, 1980, the NRC Commissioners issued Memorandum and Order CLI-80-21, which describes the NRC environmental qualification requirements. CLI-80-21 states that the Division of Operating Reactors guidelines and NUREG-0588 set the requirements that licensees and applicants must meet regarding the environmental qualification of safety-related electrical equipment to satisfy 10 CFR 50, Appendix A, GDC 4. In February 1980, the NRC included Indian Point Unit 2 in the systematic evaluation program for the purpose of the equipment environmental qualification review. On March 5, 1980, Con Edison was formerly asked to address the environmental qualification of safety-related electrical equipment for Indian Point Unit 2. This evaluation information was detailed in several responses. The original response was transmitted to the NRC by Con Edison on May 9, 1980,7 with additional information in subsequent transmittals. 8 - 10 This information was evaluated and a safety evaluation report (SER) was issued by the NRC on May 21, 1981. The Con Edison response to this SER was made on September 4, 1981.11 As a result of this SER, containment accident pressure was changed to 40.6 psig with a saturation temperature of 287 F, and this information was recorded as a part of the review for the 0 September 4, 1981 response 11 to the NRC Staff SER. The assessment of additional electrical equipment was provided to the NRC Staff by Con Edison submittal dated May 4, 1982.12 Included in this program were evaluations of the following variables and environmental parameters: function, service, location, operating time, temperature, pressure, relative humidity, chemical spray, radiation, aging, submergence, and qualifying method. This evaluation program was based on the provisions of the Guidelines for Evaluating Environmental Qualification of Class 1E Electrical Equipment in Operating Reactors (DOR Guidelines), or NUREG-0588, Interim Staff Position on Environmental Qualification of Safety Related Electrical Equipment, December 1979. The information submitted by Con Edison was evaluated by the Franklin Research Center and a technical evaluation report (TER) was issued in June 1982. A safety evaluation report was subsequently issued in January 1983 with the TER as an attachment. Con Edison responded to the safety evaluation report items and also presented the general methodology for compliance with 10 CFR 50.49, Environmental Qualification of Electrical Equipment, which had become effective in February 1983, in a submittal to the NRC in October 1984. 13 In accordance with schedule requirements for environmental qualification contained in 10 CFR 50.49, all components falling within the scope of this program were to be qualified, replaced, or modified to ensure their operation. The submittal was evaluated by the NRC and a final resolution was issued in December 1984.14 The NRC evaluation concluded the following:
1. Con Edison's electrical equipment environmental qualification program complies with the requirements of 10 CFR 50.49.

2. The proposed resolution for each of the environmental qualification items identified in the safety evaluation report of January 1983 is acceptable.

3. Continued operation until completion of the licensee's environmental qualification program will not present undue risk to the public health and safety.
Chapter 7, Page 6 of 109 Revision 20, 2006 OAG10000215_0918
IP2 FSAR UPDATE A comprehensive list of all electrical equipment important to safety, pursuant to the environmental qualification rule, 10 CFR 50.49, has been submitted to the Nuclear Regulatory Commission by Reference 1. This list called the "EQ Master List" is periodically updated to reflect plant modifications, procedure changes, or new analysis. Further EQ evaluations were performed to support plant operation at an intermediate core therlllalp()",,~rl~\I~lof~q71:~I\II\I\I(~q83:3I\11\1\1I\J~~~)and a 1.4% power uprate to 3114.4 MW §lnqW~@:~r§~Y~!lq§lt~qfQr$tr§tqQpqW~rl~Y~lqf941gM"I\ft. LOCA containment re-analysis performed in 2000 for the replacement Steam Generators resulted in a peak containment pressure of 43 psig and a peak temperature of 263°F (FSAR Section 14.3.5.1.1). For EQ purposes, the saturation temperature of 287°F at a pressure of 40.6 psig was replaced with peak predicted temperature plus margin. EQ equipment installed in the containment is qualified to 28rF, which bounds 263°F plus 15°F margin. It is acceptable to use the peak accident temperature with margin instead of saturation temperature, as discussed in paragraph 7 of Generic Letter 82-09. Post-accident chemistry changes due to the elimination of the spray additive tank and installation of Trisodium Phosphate Baskets were evaluated and it was determined that these changes did not affect the environmental qualification of equipment located within the containment required to mitigate the consequences of design basis accidents. Complete and auditable records are available and will be maintained at a central location. These records describe the environmental qualification methods used for all safety-related electrical equipment in sufficient detail to document the degree of compliance with the DOR Guidelines, NUREG-0588, and/or 10 CFR 50.49. Such records were updated and maintained current as equipment was replaced, further tested, or otherwise further qualified. 7.1.5 Regulatory Guide 1.97 Compliance Compliance of the instrumentation at Indian Point Unit 2 with the intent of Regulatory Guide 1.97, Revision 2, as required by NUREG-0737, Supplement 1 (Generic Letter 82-33), has been addressed in submittals to the Nuclear Regulatory Commission, dated August 30, 1985 15 , September 12, 198616 , October 26, 198817 , October 27, 198918 , August 7, 1991 19 , November 19
°,
19922 November 26,1986 22 , November 15,19942 \ April 7, 199523 , and September 18,199524 . The submittals included the degree of compliance and intended upgrades or justifications where deviations of present instrumentation were identified. The NRC determined that the plant design is acceptable with respect to conformance to Regulatory Guide 1.97 Rev 2 In SERs dated September 27, 199025 , August 31, 199226 , August 27, 199327 , February 2, 199528 , and November 27, 199529 . Control room indicators and recorders for instrumentation designated as Types A, B, and C and Categories 1 and 2 of Regulatory Guide 1.97 are specifically identified on the control room panels. REFERENCES FOR SECTION 7.1
1. Letter from J. D. O'Toole, Con Edison, to S. A. Varga, NRC,
Subject:
Environmental Qualification Rule, dated May 20, 1983. Chapter 7, Page 7 of 109 Revision 20, 2006 OAG10000215_0919
IP2 FSAR UPDATE
2. J. Nay, Topical Report Supplier Post Accident Testing of Process Instrumentation, WCAP-7354-L (Proprietary), Westinghouse Electric Corporation, July 1969.

3. J. Locante, Topical Report Environmental Testing of Engineered Safety Features Related Equipment (NSSS-Standard Scope), WCAP-7410-L (Volumes I and II, Proprietary), Westinghouse Electric Corporation, December 1970

4. C. V. Fields, Fan Cooler Motor Unit Development and Test, WCAP-9003 (Proprietary), Westinghouse Electric Corporation, January 1969.

5. Westinghouse Electric Corporation, Reactor Containment Fan Cooler Motor Insulation Irradiation Testing, WCAP-7343-L (Proprietary), WCAP-7829 (Nonproprietary), July 1969.
6. 7.
8. Letter from Con Edison response to NRC,
Subject:
Response to NRC request of March 5, 1980, on Environmental Qualification Program, dated May 9, 1980.
9. Letter from Con Edison to NRC,
Subject:
Additional Material on Environmental Qualification Program, dated October 31, 1980.
10. Letter from Con Edison to NRC,
Subject:
Additional Material on Environmental Qualification Program, dated January 14, 1981.
11. Letter from Con Edison to NRC,
Subject:
Additional Material on Environmental Qualification Program, dated April 13, 1981.
12. Letter from Con Edison, to NRC,
Subject:
Response to NRC Safety Evaluation Report issued by NRC on May 21,1981, dated September 4,1981.
13. Letter from Con Edison, to NRC,
Subject:
Additional Information on Environmental Qualification of Safety Related Electrical Equipment, dated May 4, 1982.
14. Letter from J. D. O'Toole, Con Edison, to S. A. Varga, NRC,
Subject:
Environmental Qualification of Safety Related Electrical Equipment, dated October 5, 1984.
15. Letter from S. A. Varga, NRC, to J. D. O'Toole, Con Edison,
Subject:
Final Resolution of Environmental Qualification of Electric Equipment Important to Safety, dated December 7, 1984. Chapter 7, Page 8 of 109 Revision 20, 2006 OAG10000215_0920
IP2 FSAR UPDATE
16. Letter from J.D. O'Toole, Con Edison, to H.L. Thompson, Jr., NRC,
Subject:
Compliance with Guidance of Regulatory Guide 1.97, Revision 2, dated August 30, 1985.
17. Letter from M. Selman, Con Edison, to H. L. Thompson, Jr., NRC, dated September 12, 1986, with attachment "Response to Preliminary Technical Evaluation Report."

18. Letter from John Basile, Con Edison, to Document Control Desk, NRC,
Subject:
Additional Information Regarding NUREG-0737, Supplement 1 (Regulatory Guide 1.97 Revision 2), dated October 26, 1988.
19. Letter from Stephen Bram, Con Edison, to Document Control Desk, NRC,
Subject:
Clarification of Information Regarding NUREG-0737 Supplement 1 (Regulatory Guide 1.97 Revision 2) dated October 27, 1989.
20. Letter from Stephen Bram, Con Edison, to Document Control Desk, NRC,
Subject:
Supplemental Information Regarding NUREG-0737, Supplement 1 (Regulatory Guide 1.97, Revision 2) dated August 7, 1991.
21. Letter from Stephen Bram, Con Edison, to Document Control Desk, NRC,
Subject:
Supplemental Information Regarding NUREG-0737, Supplement 1 (Regulatory Guide 1.97, Revision 2) dated November 19,1992.
22. Letter from Stephen Quinn, Con Edison, to Document Control Desk, NRC,
Subject:
Steam Generator Wide Range Level Indication Upgrade (Regulatory Guide 1.97, Revision 2) dated November 15,1994
23. Letter from J. Basile, Con Edison, to M. Siosson, NRC,
Subject:
Indian Point Unit No.2, Docket No. 50-247, dated November 26, 1986.
24. Letter from Stephen E. Quinn, Con Edison, to Document Control Desk, NRC,
Subject:
Response to Request for Additional Information Regarding Neutron Flux Instrumentation (TAC No. M81727) dated April 7, 1995.
25. Letter from Stephen E. Quinn, Con Edison, to Document Control Desk, NRC,
Subject:
Supplemental Submittal Regulatory Guide 1.97 Qualification of Neutron Flux Instrumentation (TAC No. M81727) dated September 18, 1995.
26. Letter from Donald S. Brinkman, NRC, to Stephen B. Bram, Con Edison,
Subject:
Conformance to Regulatory Guide 1.97, Revision 2 (TAC No. M51098) dated September 27, 1990.
27. Letter from F. J. Williams, Jr., NRC,
Subject:
Regulatory Guide 1.97 - Instrumentation to Follow the Course of an Accident, Indian Point Nuclear Generating Unit No.2 (TAC No. M51098) dated August 31,1992.
28. Letter from F. J. Williams, NRC, to Stephen B. Bram, Con Edison
Subject:
Supplemental Safety Evaluation - Regulatory Guide 1.97 Instrumentation to Follow the Course of an Accident, Indian Point Nuclear Generating Unit NO.2 (TAC No. M81727) dated August 27, 1993. Chapter 7, Page 9 of 109 Revision 20, 2006 OAG10000215_0921
IP2 FSAR UPDATE
29. Letter from F. J. Williams, Jr., to Stephen E. Quinn, Con Edison, NRC,
Subject:
Steam Generator Wide Range Level Indication Upgrade, Indian Point Nuclear Generating Unit No.2 (TAC No. M81727) dated February 2, 1995.
30. Letter from F. J. Williams, Jr., NRC, to Stephen E. Quinn, Con Edison,
Subject:
Conformance to Regulatory Guide 1.97, Revision 2, Post-Accident Neutron Flux Monitoring Instrumentation for Indian Point Nuclear Generating Unit NO.2 (TAC No. M81727), dated November 27, 1995. Chapter 7, Page 10 of 109 Revision 20, 2006 OAG10000215_0922
IP2 FSAR UPDATE TABLE 7.1-1 (Sheet 1 of 2) Postaccident Equipment (Inside Containment) Operational and Testing Requirements Operating Environmental Equipment Name and Tag Number Mode Testing CATEGORY 1 -INSTRUMENTATION Pressurizer pressure channels: Continuous Required PT-455, 456, 457,474 Pressurizer level channels: Continuous Required LT-460, 459, 461 High-head flow channels: Continuous Required FT-924, 925, 926, 927 Steam generator level channels: Continuous Required LT-417A-C, 427A-C,437A-C, 447A-C Recirculation spray flow channels: Interm ittent Required FT-945A, B Recirculation sump level channel: Continuous Required LT-3301 Containment sump level channel: Continuous Required LT-3300 Residual heat loop flow channels: Continuous Required FT-640, 946A, B, C, D Operating Environmental Equipment Name and Tag Number Mode Testing Chapter 7, Page 11 of 109 Revision 20, 2006 OAG10000215_0923
IP2 FSAR UPDATE TABLE 7.1-1 (Sheet 2 of 2) Postaccident Equipment (Inside Containment) Operational and Testing Requirements CATEGORY 2 - VALVES Safety injection line valves: MOV-856A, C, D, E Open or close on demand 1 Required MOV-856B, F Open or close on demand 2 Required Recirculation spray valves: Open or close on demand Required MOV-889A, B Recirculation pump discharge valves: Open after injection phase, Required MOV-1802A, B close on demand Containment sump isolation valve: Open or close on demand Required MOV-1805 Residual heat exchanger cooling water Open on demand 1 Required supply valves: MOV-822A, B Residual heat exchanger isolation Open or close on demand Required valves: MOV-745A, B, 746 1, 7471 Residual heat loop flow control valves: Open or close on demand Required HCV-638, 640 Air-operated isolation valves Close on demand Not required 3 CATEGORY 3 - MISCELLANEOUS ITEMS Fan cooler motors: 21, 22, 23, 24, 25 Continuous Required Internal recirculation pump motors Start after injection phase Required and continue operating Hydrogen recombiner system Operate on demand Required Safeguard equipment power, control Continuous Required and instrument cable Notes:
1. Also open on SI signal.

2. Deenergized closed per Technical Specifications.

3. All air-operated valves fail in closed position.
Chapter 7, Page 12 of 109 Revision 20, 2006 OAG10000215_0924
IP2 FSAR UPDATE TABLE 7.1-2
...........................
DELETED TABLE 7.1-3
...........................
DELETED TABLE 7.1-4 DELETED TABLE 7.1-5 DELETED 7.1 FIGURES Figure No. Title Figure 7.1-1 ENVIRONMENTAL CONDITIONS FOR EQUIPMENT TESTING - PRESSURE VS TIME Figure 7.1-2 ENVIRONMENTAL CONDITIONS FOR EQUIPMENT TEMPERATURE VS TIME Figure 7.1-3 INSTANTANEOUS GAMMA DOSE RATE INSIDE THE CONTAINMENT AS A FUNCTION OF TIME AFTER RELEASE - TID - 14844 MODEL Figure 7.1-4 INTEGRATED GAMMA DOSE LEVEL INSIDE THE CONTAINMENT AS A FUNCTION OF TIME AFTER RELEASE - TID - 14844 MODEL Figure 7.1-5 Deleted Figure 7.1-6 Deleted Figure 7.1-7 Deleted Figure 7.1-8 Deleted 7.2 PROTECTION SYSTEMS The protection systems consist of both the reactor protection system and the engineered safety features. Equipment supplying signals to any of these protection systems is considered a part of that protection system. 7.2.1 Design Bases 7.2.1.1 Control Room Criterion: The facility shall be provided with a control room from which actions to maintain safe operational status of the plant can be controlled. Adequate radiation protection shall be provided to permit continuous occupancy of the control room under any credible post-accident condition or as an alternative, access to other areas of the facility as necessary to shut down and maintain safe control of the facility without excessive radiation exposures of personnel. (GDC 11) The plant is equipped with a control room that contains those controls and instrumentation necessary for the operation of the reactor and turbine generator under normal and accident conditions. Chapter 7, Page 13 of 109 Revision 20, 2006 OAG10000215_0925
IP2 FSAR UPDATE The control room is continuously occupied by the qualified operating personnel under all operating and maximum credible accident conditions. As part of the initial plant design, sufficient shielding, distance, and containment integrity were provided to ensure that control room personnel would not be subjected to doses under postulated accident conditions during occupancy of, ingress to, and egress from the control room, which in the aggregate, would exceed limits in 10 CFR 100. The control room ventilation consists of a system having a large percentage of recirculated air. The fresh air intake is automatically diverted to charcoal filters to remove airborne activity if monitors indicate that such action is appropriate. An earlier study was performed to evaluate the system and structures pertaining to the habitability of the control room in accordance with NUREG-0737, TMI Action Plan Requirements, item 111.0.3.4. This TMI action item was to ensure that control room operators will be adequately protected against the effects of accidental releases of toxic and radioactive gases and that the plant can be safely operated or shut down under design-basis accident conditions. The results of an evaluation for specifically measured central control room conditions 1 indicated that the radiation doses in the control room integrated over 30 days post-LOCA were below the dose guidelines. Additional radiation detectors were installed in the central control room outside air intake. As a result of an analysis of the toxic chemical data within a 5-mile radius of Indian Point, redundant toxic chemical monitors were also installed. High concentrations of the specific toxic gases of concern result in an alarm and automatic isolation of the control room. Smoke detection capability has also been provided at the central control room outside air intake. The detection of smoke results in an alarm and automatic isolation of the control room. For further information, see NRC Safety Evaluation Report (SER) dated January 27, 1982 (Reference 6). More recently the application of the NUREG-1465 alternative source term methodology for Indian Point Unit 2 includes verification that the radiological dose to control room personnel following postulated accidents remains within the limits specified in 10 CFR 50.67 as presented in Section 14.3.6.5. Chapter 7, Page 14 of 109 Revision 20, 2006 OAG10000215_0926
IP2 FSAR UPDATE 7.2.1.2 Reactor Protection System Criterion: Core protection systems, together with associated equipment, shall be designed to prevent or to suppress conditions that could result in exceeding acceptable fuel damage limits. (GDC 14) The basic reactor tripping philosophy is to define a region of power and coolant temperature conditions allowed by the primary tripping functions, the overpower high i1T trip, the overtemperature high i1T trip, and the nuclear overpower trip. The allowable operating region within these trip settings is provided to prevent any combination of power, temperature, and pressure, which would result in departure from nucleate boiling with all reactor coolant pumps in operation. Additional tripping functions such as a high pressurizer pressure trip, low pressurizer pressure trip, high pressurizer water level trip, loss of flow trip, steam and feedwater flow mismatch trip, steam generator low-low water level trip, turbine trip, safety injection trip, nuclear source and intermediate range trips, fuel cooldown trip, and manual trip are provided as backup to the primary tripping functions for specific accident conditions and mechanical failures. A dropped rod signal provides a turbine load run back if above a given power level. The dropped rod is indicated from individual rod position indicators or by a rapid neutron flux decrease on any of the power range nuclear channels (as discussed in Section 14.1.4). Intermediate Range and Power Range rod stops, Overtemperature i1T and Overpower i1T rod stops, are provided to prevent abnormal power conditions which could result from excessive control rod withdrawal initiated by operator violation of administrative procedures. The core protection system is shown schematically on the plant logic diagrams, Plant Drawings 225094 through 225107 [Formerly UFSAR Figures 7.2-1 through 7.2-14]. 7.2.1.3 Engineered Safety Features Protection System Criterion: Protection systems shall be provided for sensing accident situations and initiating the operation of necessary engineered safety features. (GDC 15) Instrumentation and controls provided for the protection systems are designed to trip the reactor, to prevent or limit fission product release from the core and to limit energy release, to signal containment isolation, and to control the operation of engineered safety features equipment. The engineered safety features systems are actuated by the engineered safety features actuation channels. Each coincidence network energizes an engineered safety features actuation device that operates the associated engineered safety features equipment, motor starters, and valve operators. The channels are designed to combine redundant sensors and independent channel circuitry, coincident trip logic, and different parameter measurements so that a safe and reliable system is provided in which a single failure will not defeat the channel function. The action initiating sensors, bistables, and logic are shown in the figures included in the detailed engineered safety features instrumentation description given in the system design section. The engineered safety features instrumentation system actuates (depending on the severity of the condition) the safety injection system, the containment isolation system, the containment air recirculation system, and the containment spray system. Chapter 7, Page 15 of 109 Revision 20, 2006 OAG10000215_0927
IP2 FSAR UPDATE The passive accumulators of the safety injection system do not require signal or power sources to perform their function. The actuation of the active portion of the safety injection system is described in Section 7.2.3. The containment air recirculation coolers are normally in use during plant operation. These units are, however, in the automatic sequence, which actuates the engineered safety features upon receiving the necessary actuating signals indicating an accident condition. The fan cooler bypass valves open on safety injection to provide maximum service water flow. Containment spray is actuated by coincident and redundant high containment pressure signals. The containment isolation system provides the means of isolating the various pipes passing through the containment walls as required to prevent the release of radioactivity to the outside environment in the event of a loss-of-coolant accident. The engineered safety features protection systems are shown schematically on the plant logic diagrams, Plant Drawings 225094 through 225107 [Formerly UFSAR Figures 7.2-1 through 7.2-14]. 7.2.1.4 Protection Systems Reliability Criterion: Protection systems shall be designed for high functional reliability and in-service testability necessary to avoid undue risk to the health and safety of the public. (GDC 19) The reactor uses the Westinghouse magnetic-type control rod drive mechanisms. Upon a loss of power to the coils, the rod cluster control (RCC) assemblies with full-length absorber rods are released and fall by gravity into the core. The undervoltage trip coils and the shunt trip coils of the reactor trip breakers are used as the primary and backup devices, respectively, for the automatically initiated reactor trip signals. The reactor internals, fuel assemblies, RCC assemblies, and drive system components are designed as seismic Class I equipment. The RCC assemblies are fully guided through the fuel assembly and for the maximum travel of the control rod into the guide tube. Furthermore, the RCC assemblies are never fully withdrawn from their guide thimbles in the fuel assembly. Because of this and the flexibility designed into the RCC assemblies, abnormal loadings and misalignments can be sustained without impairing operation of the RCC assemblies. The RCC assembly guide system is locked together with pins throughout its length to ensure against misalignments that might impair control rod movement under normal operating conditions and credible accident conditions. An analogous system has successfully undergone 4132 hr of testing in the Westinghouse reactor evaluation channel, during which about 27,200-ft of step-driven travel and 1461 trips were accomplished with test misalignments in excess of the maximum possible misalignment that may be experienced when installed in the plant. All reactor trip protection channels are supplied with sufficient redundancy to provide the capability for channel calibration and test at power. Reliability and independence are obtained by redundancy within each tripping function. In a two-out-of-three circuit, for example, the three channels are equipped with separate primary sensors. Each channel is continuously fed from its own independent electrical source. Failure Chapter 7, Page 16 of 109 Revision 20, 2006 OAG10000215_0928
IP2 FSAR UPDATE to deenergize a channel when required would be a mode of malfunction that would affect only that channel. The trip signal furnished by the two remaining channels would be unimpaired in this event. 7.2.1.5 Protection Systems Redundancy and Independence Criterion: Redundancy and independence designed into protection systems shall be sufficient to assure that no single failure or removal from service of any component or channel of such a system will result in loss of the protection function. The redundancy provided shall include, as a minimum, two channels of protection function to be served. (GDC 20) The reactor protection systems are designed so that the most probable modes of failure in each protection channel result in a signal calling for the protective trip. Each protection system design combines redundant sensors and channel independence with coincident trip philosophy so that a safe and reliable system is provided in which a single failure will not defeat the channel function, cause a spurious plant trip, or violate reactor protection criteria. Channel independence is carried throughout the system extending from the sensor to the relay actuating the protective function. The protective and control functions when combined are combined only at the sensor. Both of these functions are fully isolated in the remaining part of the channel, control being derived from the primary protection signal path through an isolation amplifier. As such, a failure in the control circuitry does not affect the protection channel. This approach is used for pressurizer pressure and water level channels, steam generator water level, Tavg and delta T channels, steam flow-feedwater flow, and nuclear source and power range channels. A nonelectrical backup to the pressurizer pressure and level indication exists that uses pneumatic transmitters with indicators located inside and outside the containment. The transmitters are supplied with air from the instrument air headers inside the containment with a backup supply from the nitrogen system also located inside the containment. The same nonelectrical backup is used to provide indication of steam-generator levels inside and outside the containment. The engineered safety features equipment is actuated by either one or both of the engineered safety features actuation channels. Each coincidence network actuates an engineered safety actuation device that operates the associated engineered safety features equipment, motor starters, and valve operators. As an example, the control circuit of a safety injection pump is typical of the control circuit for a large pump operated from switchgear. The actuation relay, energized by the engineered safety features instrumentation system, has normally open contacts. These contacts energize the circuit breaker closing coil to start the pump when the control relay is energized. In the reactor protection system, two reactor trip breakers are provided to interrupt power to the full-length rod drive mechanisms. The breakers main contacts are connected in series (with power supply) so that opening either breaker interrupts power to all full-length rod mechanisms, permitting them to fall by gravity into the core. In the event of a loss of rod control power, the reactor trip breakers are deenergized and trip to an open mode. Chapter 7, Page 17 of 109 Revision 20, 2006 OAG10000215_0929
IP2 FSAR UPDATE Further information on redundancy is provided through the detailed descriptions of the respective systems covered by the various sections in this chapter. In summary, reactor protection is designed to meet all presently defined reactor protection criteria and is in accordance with the proposed IEEE criteria for nuclear power plant protection system (I EEE-279 Code), dated August 28, 1968. Redundancy and independence are more than achieved by protection channel designs, which combine more than one sensor and Parameter measurement with coincident trip circuitry (e.g., pressure coincident with level and interlocked with flow or nuclear flux). Required continuous electrical supply is discussed in Chapter 8. 7.2.1.6 Protection Against Multiple Disability for Protection Systems Criterion: The effects of adverse conditions to which redundant channels or protection systems might be exposed in common, either under normal conditions or those of an accident, shall not result in loss of the protection function or shall be tolerable on some other basis. (GDC 23) The components of the protection system are designed and laid out so that the mechanical and thermal environments accompanying any emergency situation in which the components are required to function do not interfere with that function. The separation of redundant analog protection channels originates at the process sensors and continues back through the field wiring and containment penetrations to the analog protection racks. Physical separation is used to the maximum practical extent to achieve the separation of redundant transmitters. The separation of field wiring is achieved using separate wireways, cable trays, conduit runs, and containment penetrations for each redundant channel. Redundant analog equipment is separated by locating redundant components in different protection racks. Each channel is energized from a separate vital instrument bus. 7.2.1.7 Demonstration of Functional Operability of Protection Systems Criterion: Means shall be included for suitable testing of the active components of protection systems while the reactor is in operation to determine if failure or loss of redundancy has occurred. (GDC 25) The signal conditioning equipment of each protection channel in service at power is capable of being tested and tripped independently by simulated analog input signals to verify its operation. This includes checking through to the trip breakers, which necessarily involves the trip logic. Thus, the operability of each trip channel can be determined conveniently and without ambiguity. The testing of the diesel-generator starting is performed from the diesel-generator control board. The generator breaker is not closed automatically after starting during this testing. The generator may be manually synchronized to the 480-V bus for loading. Complete testing of the starting of diesel generators can be accomplished by tripping the associated 480-V undervoltage relays. The ability of the units to start within the prescribed time and to carry load is periodically checked. (The electrical system is discussed in more detail in Section 8.2.3.) Chapter 7, Page 18 of 109 Revision 20, 2006 OAG10000215_0930
IP2 FSAR UPDATE 7.2.1.8 Protection Systems Failure Analysis Design Criterion: The protection systems shall be designed to fail into a safe state or into a state established as tolerable on a defined basis if conditions such as disconnection of the system, loss of energy (e.g., electrical power, instrument air), or adverse environments (e.g., extreme heat or cold, fire, steam, or water) are experienced. (GOC 26) Each reactor trip circuit is designed so that circuit trip occurs when the circuit is deenergized; therefore, loss of channel power causes the system to go into its trip mode. In a two-out-of-three circuit, the three channels are equipped with separate primary sensors and each channel is energized from an independent electrical bus. Failure to deenergize when required is a mode of malfunction that affects only one channel. The trip signal furnished by the two remaining channels is unimpaired in this event. Reactor trip is implemented by interrupting power to the magnetic latch mechanisms on all drives allowing the full-length rod clusters to insert by gravity. The reactor protection system is thus inherently safe in the event of a loss of power. The engineered safety features actuation circuits are designed on the same "deenergize to operate" principle as the reactor trip circuits, with the exception of the containment spray actuation circuit, which is energized to operate in order to avoid spray operation on inadvertent power failure. Automatic starting of all emergency diesel generators is initiated by under-voltage relays on any 480-V bus or by the safety injection signal. Engine cranking is accomplished by a stored energy system supplied solely for the associated diesel generator. The undervoltage relay scheme is designed so that loss of 480-V power does not prevent the relay scheme from functioning properly. 7.2.1.9 Redundancy of Reactivity Control Criterion: Two independent control systems, preferably of different principles, shall be provided. (GOC 27) One of the two reactivity control systems employs rod cluster control assemblies to regulate the position of Ag-In-Cd neutron absorbers within the reactor core. The other reactivity control system employs the chemical and volume control system to regulate the concentration of boric acid solution (neutron absorber) in the reactor coolant system. 7.2.1.10 Reactivity Control System Malfunction Criterion: The reactor protection system shall be capable of protecting against any single malfunction of the reactivity control system, such as unplanned continuous withdrawal (not ejection or dropout) of a control rod, by limiting reactivity transients to avoid exceeding acceptable fuel damage limits. (GOC 31) Reactor shutdown with rods is completely independent of the normal control functions since the trip breakers completely interrupt the power to the full-length rod mechanisms regardless of existing control signals. Effects of continuous withdrawal of a rod control assembly and of deboration are described in Sections 7.3.1, 7.3.2, 9.2, and 14.1. Chapter 7, Page 19 of 109 Revision 20, 2006 OAG10000215_0931
IP2 FSAR UPDATE 7.2.1.11 Seismic Design For earthquake (operational basis or design basis), the equipment is designed to ensure that it does not lose its capability to perform its function, that is, shut the plant down and maintain it in a safe shutdown condition. For the maximum potential earthquake, there may be permanent deformation of equipment provided that the capability of the equipment to perform its function is maintained. The instrumentation and electrical equipment, associated with emergency core cooling, will not cause an interruption of this function during the earthquake. Instrumentation and control specifications include only static "g" level requirements. As a result of seismic criteria subsequently established, the static requirements were considered inappropriate and Westinghouse adopted the position of type testing equipment to demonstrate design adequacy. A safeguards signal may be initiated by an instrument or transmitter that has the ability to withstand seismic forces as demonstrated in WCAP-7397-L, Section 4.8. 2 This signal is carried in conduit and cable trays whose supports have been studied for resistance to seismic forces. The signal passes to the process control racks proved as described in WCAP-7397L, Section 4.2.2 The signal is sent next to the safeguards actuation racks proved as described in WCAP-7397-L, Section 4.3. 2 The actuation signal proceeds through a switch on the control board to the appropriate switch-gear. The control boards were specified to "be designed such that the maximum stresses, including simultaneous seismic accelerations of 0.S2g in the horizontal and 0.3Sg in the vertical directions, shall not dislodge or cause relative movement between components, such as to impair the functional integrity of circuits or equipment." These accelerations exceed that calculated as input to the boards from the floor of the central control room. In shipment, boards of typical manufacture and construction have recorded shocks of 8 to 10g, and when wired, the switches have operated without repair. The switchgear equipment has been specified to withstand accelerations in excess of 0.1Sg horizontally and 0.10g vertically. This capability was a matter of the procurement specification of Westinghouse and their design agents and design action of the vendors. The safeguards circuits for Indian Point Unit 2 employ Westinghouse Series W motor control centers, type DB circuit breakers, and associated metal-enclosed or metal-clad switchgear. A review of this switchgear for proof of adequacy of the seismic-resistant design determined that the Series W motor control centers and DB breakers, mounted in the metal enclosures, have been shock tested and proved to remain fully operable for shocks of at least 3g in any direction. Since original construction, five (S) new motor control centers have been installed and certain essential loads were rearranged to enhance reliability in a Loss of Offsite Power (LOOP) event. The new motor control centers were procured in accordance with IEEE-344 and seismically installed. Seismic qualification of the reactor trip breaker shunt trip attachments (type DB-SO) was performed on a generic basis by the Westinghouse Owner's Group. It has been determined that this generic qualification adequately envelopes Indian Point Unit 2 seismic parameters 4 . Proof of resistance of the similar DH metal-clad switchgear to a seismic response spectrum established for the Point Beach plant has been demonstrated by vibration testing of typical, equivalent metal-clad switchgear, incorporating the similar DHP circuit breaker. The DH circuit breakers installed in the Point Beach plant were of an earlier design than the DHP. However, the general configuration, weight distribution, and vibration-resistant design approach of the DH are essentially identical to the DHP. When subjected to a seismic spectrum equivalent to or greater than the seismic test envelope given in Figure B-2 of Reference 2, there was no loss of function of the DHP metal-clad switchgear. This seismic test envelope given in Reference 2 is estimated to include all low seismic plants, that is, plants with a design-basis Chapter 7, Page 20 of 109 Revision 20, 2006 OAG1000021S_0932
IP2 FSAR UPDATE earthquake horizontal ground acceleration of 0.2g or less. This similarity between the DH and DB circuit breakers gives added confidence in the seismic suitability of the DB circuit breakers installed at Indian Point Unit 2. The power supply leaving the switchgear operates the safeguards equipment completing the actuation train. The seismic design of this equipment is described in Sections 7.1 and 1.11. The direct current power supply may be considered as a branch to this main train of actuation. The source of direct current power is the station batteries. The Class 1E station batteries and associated battery racks have been determined to be seismically qualified for their installation locations. The conduit and cable trays carrying the direct current power to the safeguards equipment train received the same study for seismic support as described above. The seismic qualification requirements for DC power panels 21 and 22 are enveloped by the generic equipment qualification described above. Additionally, these DC power panels were evaluated using Seismic Qualification Utility Group data. The evaluation shows a significant seismic margin for the two panels 5 . Westinghouse designed and procured all systems that actuate reactor trip and safety feature actions for Indian Point Unit 2. The design of protective grade instrumentation and logic systems are in accordance with the proposed IEEE criteria for nuclear power plant protection system (lEEE-279 Code), dated August 28, 1968. The functional design is originated at Westinghouse with equipment procurement through vendor supplies. Equipment compatibility and integration of component hardware are factored into the design by Westinghouse or under the direct supervision of Westinghouse. 7.2.2 Principles of Design 7.2.2.1 Redundancy and Independence The protection systems are redundant and independent for all vital inputs and functions. Each channel is functionally independent of every other channel and receives power from an independent source. The isolation of redundant protection channels is described in further detail elsewhere in this section as well as in Section 7.2.3. 7.2.2.2 Manual Actuation Means are provided for manual initiation of protection system action. Failures in the automatic system do not prevent the manual actuation of protective functions. Manual actuation requires the operation of a minimum of equipment. 7.2.2.3 Channel Bypass or Removal From Operation The system is designed to permit anyone channel to be maintained, and when required, tested or calibrated during power operation without protection system trip. Since the channel under test is either tripped or bypassed, superimposed test signals are used that do not negate the process signal. Systems are permitted to violate the single-failure criterion during channel bypass; acceptable reliability of operation has been demonstrated and the bypass time interval is short. Chapter 7, Page 21 of 109 Revision 20, 2006 OAG10000215_0933
IP2 FSAR UPDATE 7.2.2.4 Capability for Test and Calibration The bistable portions of the protection system (e.g., relays and bistables) provide trip signals only after signals from analog portions of the system reach preset values. Capability is provided for calibrating and testing the performance of the bistable portion of protection channels and various combinations of the logic networks during reactor operation. The analog portion of a protection channel provides analog signals of reactor or plant parameters. The following means are provided to permit checking the analog portion of a protection channel during reactor operation:
1. Varying the monitored variable.

2. Introducing and varying a substitute transmitter signal.

3. Cross checking between identical channels or between channels, which bear a known relationship to each other and which have readouts available.
The design permits the administrative control of the means for manually bypassing channels or protection functions. The design permits the administrative control of access to all trip settings, module calibration adjustments, test points, and signal injection points. Protection system setpoints are maintained under procedural control and are the nominal values at which the bistables may be set. The limiting safety system settings (LSSS) for these setpoints have been determined in order to accommodate instrument drift (which is assumed to occur between operational tests) and the limitations on accuracy of measurement and calibration, and are contained in the Improved Technical Specifications as Allowable Valves. A setpoint is considered to be consistent with the nominal value when the "as left" value is within the band allowed for calibration accuracy, as defined by the plant setpoint study and calibration procedures. 7.2.2.5 Information Readout and Indication of Bypass The protection systems are designed to provide the operator with accurate, complete, and timely information pertinent to their own status and to plant safety. Indication is provided in the control room if some part of the system has been administratively bypassed or taken out of service. Trips are indicated and identified down to the channel level. 7.2.2.6 Safeguards Initiating Circuitry The safeguards actuation circuitry and hardware layout are designed to maintain required circuit isolation throughout, from the process sensors through the slave relays, which actuate individual safeguards components. The channelization design is shown in Plant Drawing 243318 [Formerly UFSAR Figure 7.2-15]. The safeguards bistables, mounted in the analog protection racks, drive both A and B logic matrix relays. Each individual coincident matrix contains its own test light and test circuitry. The A and B logic matrices operate separate master relays to actuate channels A and B, respectively, as shown in Plant Drawing 243319 [Formerly UFSAR Figure 7.2-16]. Control power for logic trains A and B, is supplied from separate direct current sources 1 and 2, Chapter 7, Page 22 of 109 Revision 20, 2006 OAG10000215_0934
IP2 FSAR UPDATE respectively. These redundant actuating channels operate the various safeguards components required, with the large loads sequenced as necessary. Manual reset of the safeguards actuation relays may be accomplished 2 min following their operation. Manual initiation will override reset and result in safeguards actuation at all times. Protection channel identity is lost in the intermixing of the relay matrix wiring. Physical separation of A and B logic trains is maintained by the separate logic racks. 7.2.2.7 Analog Channel Testing The basic elements composing an analog protection channel are shown in Plant Drawing 243320 [Formerly UFSAR Figure 7.2-17]. This system consists of a transmitter, power supply, bistable, bistable trip switch and proving lamp, test signal injection switch, test signal injection jack, and test point. Each protection rack includes a test panel containing those switches, test jacks, and related equipment needed to test the channels contained in the rack. A hinged cover encloses the signal injection switch and signal injection jack of the test panel. Opening the cover or placing the test operate switch in the "test" position initiates an alarm identifying the rack under test. These alarms are arranged on a rack basis to preclude entry to more than one redundant protection rack (or channel) at any time. The test panel cover is designed such that it cannot be closed (and the alarm cleared) unless the test device plugs (described below) are removed. Closing the test panel cover mechanically returns the test switches to the "normal" position. To minimize the risk of a trip during on-line testing of instrument channels, the bistables are bypassed to maintain the logic relays energized. A proving lamp across the bistable output facilitates checking the bistable trip setting during channel calibration. The bistable trip switches must be manually reset after the completion of a test. Closing the test panel cover will not restore these switches to the untripped mode. Procedures limit bistable testing to one circuit at a time. Actual channel calibration consists of producing a test signal using the transmitter power supply external calibration device, which plugs into the signal injection jack. In this application, where specified the channel power supply serves as a power source for the calibration device to permit verifying the output load capacity of the power supply. Test points are located in the analog channel and provide an independent means of measuring and/or monitoring the calibration signal level. 7.2.2.8 Logic Channel Testing Testing of the logic matrices is described in UFSAR Section 7.2.4.6. 7.2.2.9 Isolation of Reactor Protection and Engineered Safety Feature Signals The following device is used to ensure that electrical isolation exists between protection and control grade signals: where protection signal intelligence is required for other than protection functions, an isolation amplifier (part of the protection set) is used to transmit the intelligence. The isolation amplifier prevents the perturbation of the protection channel signal (input) due to Chapter 7, Page 23 of 109 Revision 20, 2006 OAG10000215_0935
IP2 FSAR UPDATE any disturbance of the isolated signal (output), which could occur near any termination of the output wiring external to the protection racks. A detailed discussion of the isolation amplifiers that are used in Indian Point Unit 2 is given in WCAP-9011. 3 The isolation of reactor protection and engineered safety feature signals in the reactor protection logic racks is achieved by physical separation and circuit protection to meet the single failure criteria. There are three decks containing the contacts on each logic relay used. The configuration, in general, utilizes the rear deck for reactor protection and engineered safety feature signals. The center and front decks are typically used for annunciator and computer signals, respectively. The necessary isolation between the safety signals and the annunciator and/or computer signals is provided at the contacts of the relays. Separation is typically maintained by using separate wireways for safety signals, annunciator signals, and computer signals. The design basis for protection of reactor protection and engineered safety system circuit cables include protection from failure of other non-safety system circuit cables routed in the same raceway by having the non-safety cables (like safety cables) (a) designed using conservative margins with respect to their current carrying capacities, insulation properties, and mechanical construction, (b) protected against overloads by coordinated fuses or circuit breakers, and (c) fire retardant. 8 7.2.2.10 Vital Protection Functions and Functional Requirements The reactor protection system monitors those parameters related to safe operation and trips the reactor to protect the reactor core against fuel rod cladding damage caused by departure from nucleate boiling, and to protect against reactor coolant system damage caused by high system pressure. The engineered safety features instrumentation system monitors parameters to detect failure of the reactor coolant system and initiates containment isolation and engineered safety features operation to contain radioactive fission products. Section 7.2 covers those protection systems provided to:
1. Trip the reactor to prevent or limit fission product release from the core and to limit energy release.

2. Isolate containment and activate the isolation valve seal water system and weld channel penetration pressurization system when necessary.

3. Control the operation of engineered safety features provided to mitigate the effects of accidents.
The core protection systems in conjunction with inherent plant characteristics are designed to prevent anticipated abnormal conditions from causing fuel damage exceeding limits established in Chapter 3, or reactor coolant system damage exceeding effects established in Chapter 4. 7.2.2.11 Completion of Protective Action Where operating requirements necessitate automatic or manual bypass of a protection function, the design is such that the bypass is removed automatically whenever permissive conditions are not met. Devices used to achieve automatic removal of the bypass of a protective function are part of the protection system and are designed in accordance with the criteria of this section. Chapter 7, Page 24 of 109 Revision 20, 2006 OAG10000215_0936
IP2 FSAR UPDATE The protection systems are so designed that, once initiated, a protective action goes to completion. Return to normal operation requires administrative action by the operator. 7.2.2.12 Multiple Trip Settings Where it is necessary to change to a more restrictive trip setting to provide adequate protection for a particular mode of operation or set of operating conditions, the design provides positive means of ensuring that the more restrictive trip setting is used. The devices used to prevent improper use of less restrictive trip settings are considered a part of the protection system and are designed in accordance with the other provisions of these criteria. 7.2.2.13 Interlocks and Administrative Procedures Interlocks and administrative procedures required to limit the consequences of fault conditions other than those specified as limits for the protection function comply with the protection system criteria. 7.2.2.14 Deleted 7.2.3 System Design 7.2.3.1 Reactor Protection System Description Plant Drawing 243321 [Formerly UFSAR Figure 7.2-18] is a block diagram of the reactor protection system. Reactor trips are described in Section 7.2.5.1. Figure 7.2-19 illustrates the core thermal limits and shows the trip points that are used for the protection system. The solid lines are a locus of limiting design conditions representing the core thermal limits at four pressures. The core thermal limits are based on the conditions, which yield the applicable limit value for departure from nucleate boiling ratio (DNBR) or those conditions, which preclude bulk boiling at the vessel exit. The dashed lines indicate the maximum permissible trip points for the over-temperature high i1T reactor trip including allowances for measurement and instrumentation errors. The maximum and minimum pressures shown (2440 and 1860 psia) represent the limiting setpoints for the high-pressure and low-pressure reactor trips. Adequate margins exist between the worst steady-state operating point (including all temperature, calorimetric, and pressure errors) and required trip points to preclude a spurious plant trip during design transients. 7.2.3.2 Engineered Safety Features Instrumentation Description Plant Drawings 225102,225103, and 225104 [Formerly UFSAR Figures 7.2-9,7.2-10, and 7.2-12] show the logic diagrams, and Plant Drawings 243313 and 243314 [Formerly UFSAR Figures 7.2-20 and 7.2-21] show the level and pressure action initiating sensors and bistables for the engineered safety features instrumentation. Chapter 7, Page 25 of 109 Revision 20, 2006 OAG10000215_0937
IP2 FSAR UPDATE 7.2.3.2.1 Indication All transmitted signals (flow, pressure, temperature, etc.), which can cause a reactor trip, are either indicated or recorded for every channel. The channel isolation and separation criteria as described for the reactor protection circuits are applied to the engineered safety features actuation circuits. 7.2.3.2.2 Protective Actions The engineered safety features actuation system automatically performs the following vital functions:
1. Start operation of the safety injection system upon low pressurizer pressure signal, or high containment pressure signals (high pressure and high-high pressure), or on high differential pressure between any two steam generators, or on coincidence of high steam flow in any two steam lines (automatically blocked when Tavg and steam pressure are above certain limits).

2. Operate the containment ventilation isolation valves and the automatic containment isolation valves in nonessential process lines (phase A containment isolation) and generate a feedwater isolation signal upon detection of a safety injection signal as described in item 1 above. The isolation valve seal water system (lVSW) and the weld channel penetration pressurization system (WCPPS) are actuated automatically by the containment isolation signal. In addition, a high containment or plant ventilation radioactivity signal will operate the containment ventilation isolation valves.

3. Start the containment spray system and close the main steam line isolation valves upon detection of a higher containment pressure signal than in item 2 above (high-high containment pressure). The containment spray signal will operate the remaining automatic containment isolation valves (Phase B containment isolation) and the containment ventilation isolation valves. In addition, the main steam line isolation valves will close upon receipt of a signal from the steam line break protection logic.

4. Start operation of the safeguards equipment actuation sequence signal. This includes actuation signals to such components as auxiliary feedwater pumps, service water pumps, fan coolers, and diesel generators.
7.2.3.2.3 Safety Injection Trips The safety injection is provided to detect breaks in the primary or secondary systems and to initiate operation of components associated with the engineered safeguards system. The reactor is tripped upon receipt of a safety injection signal to limit the severity of the accident. The initiation of these signals is discussed in this section. The safety injection signal diagram is shown in Plant Drawing 225105 [Formerly UFSAR Figure 7.2-12]. The safety injection trip signal is initiated by anyone of the following events: Chapter 7, Page 26 of 109 Revision 20, 2006 OAG10000215_0938
IP2 FSAR UPDATE
1. Low pressurizer pressure.

2. Steam break upstream of the steam line isolation valves.

3. Steam break downstream of the steam line isolation valves.

4. High containment pressure (approximately 2 psig).

5. High-high containment pressure (approximately 24 psig).

6. Manual signal.
In addition to providing a reactor trip, the safety injection signal will:
1. Initiate a turbine trip, which will, after an approximate 30 second delay, initiate a generator trip and bus transfer.

2. Initiate a feedwater system isolation.

3. Initiate a safeguards equipment sequence signal, including starting of the diesels.

4. Initiate a containment ventilation isolation.

5. Initiate a containment phase A isolation.

6. Place-the isolation valve seal water system and weld channel penetration pressurization system into service.
7.2.3.2.3.1 Low Pressurizer Pressure This particular phase of the safety injection trip signal is provided to shut down the reactor in the event of a break in the reactor coolant system whereby the reactor coolant would be released either to containment or to the secondary side of the steam generators, depending on the location of the leak. This trip also serves as a backup to the steam break protection logic for the secondary plant. A steam break would be accompanied by excessive heat removal from the primary coolant and a rapid reduction in Tavg. This in turn will cause a drop in pressurizer pressure as well as an increase in reactivity. There are three low pressurizer pressure channels, and any two of the three initiates a safety injection signal before pressurizer pressure drops below 1801 psig, in accordance with Technical Specification requirements. Pressurizer level channels that previously were included in this logic were eliminated as a direct result of the TMI incident, which demonstrated that pressurizer level will rise if the primary system leakage path is above the pressurizer vapor space. The pressurizer pressure signals are derived from the same channels used for the low-pressure reactor trip; however lead/lag units are not used. This trip is manually bypassed on a reactor coolant system cool down once the pressure (as sensed by two-out-of-three channels) has been reduced below 1940 psig, by manual action of the "Block SI" switch on the safeguards panel. This bypass will be automatically removed when pressurizer pressure exceeds 1940 psig. A manual unblock feature is also provided for the case where it is desired to place this circuit back in service following a block signal and with the pressurizer pressure below 1940 psig. The low pressurizer pressure signal logic is shown schematically in Plant Drawing 225105 [Formerly UFSAR Figure 7.2-12]. Chapter 7, Page 27 of 109 Revision 20, 2006 OAG10000215_0939
IP2 FSAR UPDATE 7.2.3.2.3.2 Steam Line Break Upstream of Steam Line Isolation Valves/High Steam Line i1P A steam line break in this section of pipe would be characterized by a low steam-generator pressure because the nonreturn valve would close and the particular steam generator in question would feed directly into containment or to the atmosphere through the open-ended pipe. An absolute value of steam-generator pressure cannot be used to indicate this type of break because the steam-generator pressure will vary from atmospheric pressure to a no-load value of approximately 1000 psig during startup and then back down to approximately 700 psig as full load is reached. Therefore, a comparison circuit (as shown in Plant Drawing 225103 [Formerly UFSAR Figure 7.2-10]) is employed whereby each steam generator's pressure is compared to the pressure in each of the other three steam generators. A two-out-of-three logic is employed such that if a given steam-generator's differential pressure increases above a fixed setpoint when compared to two of the remaining three steam generators, a safety injection signal will be initiated. A steam generator being out of service would not affect the logic because, in this case, there will be a reverse reactor coolant flow through the steam generator and the pressure in the steam generator would be that corresponding to the saturation point for the reactor inlet temperature. This will be approximately 1000 psig assuming the air-operated steam line isolation valve was closed. If this valve were not closed, the pressure in the steam generator out of service would just follow that of the remaining steam generators, and likewise, this would not affect the logic. Although three-loop operational capability is possible on a continued basis, the plant Technical Specifications do not permit this mode of operation. A steam line break, whether it be upstream or downstream of the isolation valves, will result in a cooldown of the reactor coolant system and a subsequent addition of reactivity, due to the negative moderator temperature coefficient, and also a decrease in the reactor coolant system water volume, due to the density change as discussed in Section 14.2.5.1. The safety injection signal, as previously discussed, will initiate safeguards systems to protect against the adverse conditions resulting from the steam line break. 7.2.3.2.3.3 Steam Line Break Downstream of the Isolation Valves A steam line break in this section of pipe will be characterized by an abnormally high steam flow in the four steam lines because they are cross connected in a header arrangement and will all feed the break. To prevent the steam generators from continuing to feed the break, this particular mode of steam line break protection will close the four main steam isolation air-operated check valves. An absolute value of steam flow cannot be used to initiate the protection since the steam flow will vary from 0 Ib/hr at cold shutdown to approximately 3.5 x 106 Ib/hr per steam generator at full load. Therefore, a comparison circuit is used in which steam flow is compared to a programmed signal on the basis of turbine inlet pressure. Steam flow is sensed by measuring the differential pressure (i1P) across a steam flow element in the main steam line. One flow element and two i1p transmitters are used for each main steam line associated with each steam generator; the steam flow is proportional to the square root of the i1P across the nozzles. For this particular circuit, however, the steam flow signal is not used, but the steam flow squared or i1P signal is used (steam flow squared -i1P). Chapter 7, Page 28 of 109 Revision 20, 2006 OAG10000215_0940}}

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